FirstEnergy Transmission Affiliates Pre-Qualification

Transcription

FirstEnergy Transmission Affiliates
Pre-Qualification Submittal for
Designated Transmission Entity Status
Submitted to PJM on June 27, 2013
Table of Contents
Section
Title
(A)
Name and Address of the Entity with Point of Contact
(include parent company, affiliates or partners)
(B)
Technical & Engineering Qualifications
(C)
Demonstrated experience of the entity or its affiliate
to develop, construct, maintain and operate
transmission facilities
(D)
Prior record of the entity or its affiliate to adhere to
standardized construction, maintenance and
operating practices
(E)
Capability of the entity or its affiliate to adhere to
standardized construction, maintenance and
operating practices
(F)
Financial statements of the entity or its affiliate; to
include most recent fiscal quarter, most recent three
fiscal years or period of existence of the entity
(G)
Commitment by the entity to execute the
Consolidated Transmission Owners Agreement
(H)
Evidence demonstrating the ability of the entity to
address and timely remedy failure of the facilities
(I)
Evidence of the entity’s ability to acquire rights of
way
1
(A)
Name and Address of Parent and Affiliates with Point of Contact
Parent:
FirstEnergy Corporation (FirstEnergy)
76 S. Main Street
Akron, OH 44308
Affiliates – FirstEnergy Transmission Owners:
American Transmission Systems, Inc (ATSI)
76 S. Main Street
Akron, OH 44308
Trans-Allegheny Interstate Line Company (TrAILCo)
800 Cabin Hill Drive
Greensburg, PA 15601
Jersey Central Power & Light Company (JCP&L)
300 Madison Avenue
Morristown, NJ 07962
Metropolitan Edison Company (Met-Ed)
2800 Pottsville Pike
Reading, PA 19640
Pennsylvania Electric Company (Penelec)
5404 Evans Road
Erie, PA 16509
Monongahela Power Company (Mon Power)
1310 Fairmont Avenue
Fairmont, WV 26554
The Potomac Edison Company (Potomac Edison)
West Penn Power Company (West Penn Power)
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Contact Representative for Parent and Transmission Affiliates:
Primary:
Richard O’Callaghan
Director, Transmission & Substation Design
FirstEnergy Service Company
76 S. Main Street
Akron, OH 44308
(330) 255-1679
ocallaghanr@firstenergycorp.com
Alternate:
Cheryl Orner
General Manager, External Engineering Services
FirstEnergy Service Company
PO Box 16001
Reading, PA 19612
(610) 921-6221
corner@firstenergycorp.com
Corporate Structural Summary:
FirstEnergy is a regional energy provider headquartered in Akron, Ohio. Its
subsidiaries and affiliates are involved in the generation, transmission,
distribution and sale of electricity, as well as energy management and other
energy-related services. FirstEnergy is a publicly traded corporation. JCP&L,
Met-Ed and Penelec are wholly-owned direct subsidiaries of FirstEnergy. Mon
Power, Potomac Edison and West Penn Power are wholly-owned direct
subsidiaries of Allegheny Energy, Inc., which is a wholly-owned direct subsidiary
of FirstEnergy. ATSI and TrAILCo are wholly-owned direct subsidiaries of
FirstEnergy Transmission, LLC, which is a wholly-owned subsidiary of
Allegheny Energy, Inc.
FirstEnergy has 10 utility operating companies, forming one of the nation’s
largest investor-owned electric systems based on six million customers served
within a nearly 65,000 square-mile area of Ohio, Pennsylvania, Maryland, West
Virginia, New Jersey and New York. In addition, FirstEnergy has two multi-state
stand-alone transmission companies. FirstEnergy has $50 billion in assets with
$15 billion in annual revenues and is ranked 181 out of Fortune Magazine’s top
500 U.S. companies.
FirstEnergy, through its subsidiaries, is a PJM member. FirstEnergy
representatives are actively involved in various PJM Committees, SubCommittees, Task Forces, User Groups, Working Groups and Stakeholder
Groups.
The eight FirstEnergy Transmission Owners – ATSI, TrAILCo, JCP&L, Met-Ed,
Penelec, Mon Power, Potomac Edison and West Penn Power – operate
approximately 24,000 miles of transmission lines connecting the Midwest and
Mid-Atlantic regions. (For the purposes of this Submittal, the transmission lines
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and other transmission facilities of the FirstEnergy Transmission Owners will be
collectively referred to as the “FirstEnergy Transmission System.”)
FirstEnergy’s generation subsidiaries control approximately 20,000 megawatts of
capacity from a diversified mix of scrubbed coal, nuclear, natural gas, oil,
hydroelectric, pumped-storage and contracted wind and solar resources, including
more than 2,400 megawatts of renewable energy.
FirstEnergy Solutions, the FirstEnergy competitive subsidiary, is one of the
nation’s largest competitive electric suppliers, serving more than 2.6 million
residential, commercial and industrial customers in Ohio, Pennsylvania, New
Jersey, Maryland, Michigan and Illinois.
ATSI owns, operates and maintains over 8,100 circuit-miles of transmission lines,
substations and other transmission facilities operated at nominal voltages of 345
kV, 138 kV and 69 kV located solely in the ATSI Zone of PJM. The ATSI
system has tie-lines to the neighboring transmission systems of American Electric
Power (AEP), Dayton Power and Light, International Transmission Company,
Duquesne Light Company (DLCO), Cleveland Public Power, Buckeye Power,
Inc., American Municipal Power, Inc. and ATSI affiliate, West Penn Power and
Mon Power. The ATSI system was integrated into PJM on June 1, 2011. As a
result, PJM became the Reliability Coordinator, Balancing Authority,
Transmission Operator and Transmission Planner for all ATSI 100 kV and above
facilities. ATSI is permitted by Attachment H-21 of the PJM OATT to recover
costs for its transmission facilities. ATSI does not own or operate any distribution
or generation facilities.
TrAILCo owns, operates and maintains over 180 circuit-miles of transmission
lines, substations and other transmission facilities operated at nominal voltages of
500 kV, 345 kV, 230 kV, 138 kV and 115 kV1, including the Trans-Allegheny
Interstate Line which became commercially operational on May 19, 2011, and the
Black Oak SVC which became commercially operational in December 2007.
Currently, TrAILCo’s operating assets are located in the Allegheny Power Zone,
with projects in the Met-Ed and Penelec Zones under construction. In the future,
TrAILCo expects to construct, own, operate and maintain new transmission
facilities required by the RTEP in all of the FirstEnergy Zones. TrAILCo is
interconnected to the neighboring transmission systems of Dominion Virginia
Power (DVP), AEP and TrAILCo affiliates Mon Power, Potomac Edison and
West Penn Power. PJM is the Reliability Coordinator, Balancing Authority,
Transmission Operator and Transmission Planner for all TrAILCo 100 kV and
above facilities. TrAILCo is permitted by Attachment H-18 of the PJM OATT to
recover costs for facilities it may own, operate and maintain in the Allegheny
Power, Penelec, Met-Ed, JCP&L and ATSI Zones. TrAILCo does not own or
operate any distribution or generation facilities.
Penelec owns, operates and maintains 3,161 circuit miles of transmission lines,
1
TrAILCo owns and operates limited 765 kV facilities but does not own any 765 kV transmission lines.
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kV, 345 kV, 230 kV, 138 kV, 115 kV and 46 kV. Penelec has tie-lines with
neighboring transmission systems of PP&L Electric Utilities (PP&L), New York
State Electric & Gas, National Grid, Allegheny Electric Cooperative (AEC) and
affiliates ATSI, Met-Ed, Potomac Edison and West Penn Power. PJM is the
Reliability Coordinator, Balancing Authority, Transmission Operator and
Transmission Planner for all Penelec 100 kV and above facilities. Penelec is
permitted by Attachment H-6 of the PJM OATT to recover costs for its
transmission facilities. Penelec also owns and operates distribution facilities but
does not own or operate any generation facilities.
Met-Ed owns, operates and maintains 1,422 circuit miles of transmission lines,
kV, 230 kV, 138 kV, 115 kV, 69 kV and 34.5 kV. MetEd has tie-lines with
neighboring transmission systems of PP&L, Philadelphia Electric Company, AEC
and affiliates Penelec, Potomac Edison and JCP&L. PJM is the Reliability
Coordinator, Balancing Authority, Transmission Operator and Transmission
Planner for all Met-Ed 100 kV and above facilities. MetEd is permitted by
Attachment H-5 of the PJM OATT to recover costs for its transmission facilities.
Met-Ed also owns and operates distribution facilities but does not own or operate
any generation facilities.
JCP&L owns, operates and maintains 2,569 circuit miles of transmission lines,
kV, 230 kV, 115 kV and 34.5 kV. JCP&L has tie-lines with neighboring
transmission systems of PP&L, Long Island Lighting Company, Central Hudson
Gas & Electric Company, Public Service Electric & Gas, Atlantic City Electric
Company and affiliate Met-Ed. JCP&L is permitted by Attachment H-4 of the
PJM OATT to recover costs for its transmission facilities. PJM is the Reliability
Coordinator, Balancing Authority, Transmission Operator and Transmission
Planner for all JCP&L 100 kV and above facilities. JCP&L also owns and
operates distribution and generation facilities.
Potomac Edison owns, operates and maintains 2,042 circuit miles of transmission
500 kV, 230 kV, 138 kV and 115 kV. Potomac Edison has tie-lines with
neighboring transmission systems of DVP, Potomac Electric Power Company and
affiliates Met-Ed, Mon Power, Penelec, TrAILCo and West Penn Power. PJM is
the Reliability Coordinator, Balancing Authority, Transmission Operator and
Transmission Planner for all Potomac Edison 100 kV and above facilities.
Potomac Edison is permitted by Attachment H-11 of the PJM OATT to recover
costs for its transmission facilities. Potomac Edison also owns and operates
distribution facilities but does not own or operate any generation facilities.
Mon Power owns, operates and maintains 2,211 circuit miles of transmission
500 kV, 345 kV and 138 kV2. Mon Power has tie-lines with neighboring
transmission systems of AEP, DVP and affiliates ATSI, Potomac Edison,
2
Mon Power owns and operates limited 765 kV facilities but does not own any 765 kV transmission lines.
5
TrAILCo and West Penn Power. PJM is the Reliability Coordinator, Balancing
Authority, Transmission Operator and Transmission Planner for all Mon Power
100 kV and above facilities. Mon Power is permitted by Attachment H-11 of the
PJM OATT to recover costs for its transmission facilities. Mon Power also owns
and operates distribution and generation facilities.
West Penn Power owns, operates and maintains 4,106 circuit miles of
transmission lines, substations and other transmission facilities operated at
nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV and 115 kV. West Penn
has tie-lines with neighboring transmission systems of AEP, DLCO and affiliates
ATSI, TrAILCo, Mon Power, Penelec, Potomac Edison and TrAILCo. PJM is
the Reliability Coordinator, Balancing Authority, Transmission Operator and
Transmission Planner for all West Penn Power 100 kV and above facilities. West
Penn Power is permitted by Attachment H-11 of the PJM OATT to recover costs
for its transmission facilities. West Penn Power also owns and operates
distribution facilities but does not own or operate any generation facilities.
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(B)
Technical and Engineering Qualifications
The FirstEnergy Transmission System spans seven states and five PJM Transmission
Zones and consists of approximately 24,000 miles of transmission lines. To assure that
the system is operated reliably, assessments of the system are conducted annually by the
FirstEnergy Transmission Owners and PJM. This is accomplished by evaluating system
reliability against the federally-mandated Reliability Standards established by the North
American Electric Reliability Corporation (NERC) and approved by the Federal Energy
Regulatory Commission (FERC), the PJM reliability criteria, and the FirstEnergy
Transmission Planning Criteria.
The PJM assessment process follows the rigorous Regional Transmission Expansion
Planning Protocol which develops the Regional Transmission Expansion Plan (RTEP)
focusing on five-year and 15-year timeframes with the results shared through the PJM
stakeholder process. Representatives of the FirstEnergy Transmission Owners actively
participate in the PJM planning process and use this process to evaluate system
conditions for future years. Results of these studies drive system upgrades to the overall
PJM transmission system, including the FirstEnergy Transmission System.
In addition, the FirstEnergy Transmission Owners perform internal studies that assess the
FirstEnergy Transmission System and associated sub-transmission systems through nearterm and long-term planning windows. These internal studies identify thermal, voltage,
voltage stability and dynamic stability issues on the transmission and sub-transmission
systems. The PJM and FirstEnergy assessments ensure the FirstEnergy Transmission
System and associated sub-transmission systems are operated in a reliable and secure
manner. Models are created representing a wide variety of load levels and stressed
conditions depending on the type of study being performed. When a potential criteria
violation is identified, further study is initiated to determine if it can be resolved by a
formal operating procedure and if a system upgrade is warranted. If a system upgrade is
determined to be needed and is authorized by management, the upgrade is installed
subject to any necessary PJM reviews.
As mentioned previously both the PJM RTEP and the FirstEnergy Transmission Owners’
internal assessments identify potential projects throughout the FirstEnergy Transmission
System footprint which are further reviewed and upgrades implemented where required
to improve the reliability of the FirstEnergy transmission and sub-transmission systems.
The FirstEnergy Transmission Owners have significant experience as Transmission
Owners in responding to PJM’s directives to build RTEP projects, and have never failed
to build projects that PJM has determined are needed for reliability or market efficiency
of the PJM transmission system. The FirstEnergy Transmission Owners build, operate
and maintain their transmission facilities reliably and safely and in accordance with all
governmental regulations as well as applicable industry requirements.
FirstEnergy has three main transmission design offices staffed with engineers and
designers.3 At these locations, FirstEnergy trained and experienced engineers perform
design, procurement and regulatory permitting activities necessary for the construction
and modification of transmission lines and substations ranging from 34.5 kV up to 500
3
FirstEnergy’s design offices are located in Akron, Ohio; Reading, Pennsylvania; and Greensburg,
Pennsylvania.
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kV.4 In addition to these professionals, FirstEnergy has a cadre of trained and
experienced personnel dedicated to transmission system construction, operation and
maintenance stationed throughout the entire FirstEnergy transmission system footprint.
FirstEnergy engineers and support personnel provide a comprehensive suite of energy
services that drive transmission construction. This is accomplished through their
combined experience and knowledge of the technical, engineering and infrastructure
requirements for transmission construction, including the power engineering services
necessary for transmission lines, substation facilities, protection and controls. Overall,
FirstEnergy’s personnel have extensive direct, hands-on experience with all phases of
design, build, maintenance and operation of the transmission system.
Working in coordination with PJM, FirstEnergy professionals work to develop the best,
most cost-effective solution to the reliability and market efficiency needs of the
transmission system based on PJM’s determination of the need for reliability and market
efficiency improvements. Proactively over the years, FirstEnergy engineers have worked
with PJM through multiple iterations of studies, cost estimates, right-of-way (ROW) and
other regulatory considerations to ensure the final plans for construction of RTEP
projects are the most effective and cost efficient. Over the years, FirstEnergy has
developed an excellent working relationship with PJM Staff to facilitate discussions and
reviews of the electrical need and the proposed solution for various transmission projects
and has worked successfully with PJM to produce the best outcome.
FirstEnergy has long-term alliances with several design firms including Burns &
McDonnell, Black & Veatch and TRC. FirstEnergy’s in-house staff is currently
supplemented by about 205 full time equivalents from these and other firms for design
work to perform necessary support on projects when in-house staff is unavailable to
complete the work in a timely manner necessary. In addition, FirstEnergy maintains lists
of certified contractors with proven records of building transmission projects. When
these contractors are retained to construct a project, FirstEnergy professionals provide
oversight management of the construction process including cost control, quality review
and completion times.
Recently, FirstEnergy announced plans to build a series of PJM RTEP projects to
enhance reliability across its five PJM Transmission Zones. This initiative, known as
“Energizing the Future,” will include transmission projects – new or rebuilt high voltage
power lines, new substations and the installation of specialized voltage regulating
equipment. PJM has determined the projects are needed to enhance system reliability as
the result of the deactivation of certain generating facilities.
One of the key projects included in the initiative is the construction by ATSI of a new
345 kV transmission line in excess of 100 miles from the Bruce Mansfield Plant in
Beaver County, Pennsylvania, to a new substation in the Cleveland suburb of
Glenwillow. As designed, the new substation will connect with two existing 345 kV
transmission lines in the Glenwillow area. To minimize impacts to property owners,
approximately 70 percent of the project will consist of adding another circuit to existing
4
FirstEnergy engineers have professional licenses in the states in which FirstEnergy operates
transmission facilities.
8
structures. In addition, much of the remaining length of the project will involve the use
of existing ROW already controlled by ATSI. The route for this project, which traverses
part of Cuyahoga, Summit, Portage, Mahoning, Columbiana, and Trumbull Counties in
Ohio, and Beaver County, Pennsylvania, has been approved in Ohio by the Ohio Power
Siting Board. The construction of the transmission line and substation will occur
simultaneously in order to meet PJM’s June 2015 in-service date.
One of FirstEnergy’s past transmission line construction successes is the 500 kV TransAllegheny Interstate Line (TrAIL) approved by PJM in 2006. TrAIL consists of 661
structures and extends 180 miles from southwestern Pennsylvania across West Virginia
to northern Virginia. The project includes the construction of the 502 Junction Substation
and modifications to other substations. The project was energized on May 19, 2011 two
weeks prior to the June 1, 2011 in-service date set by PJM. This new line was needed to
meet the demand for electricity in the mid-Atlantic region and prevent overloading on the
transmission grid.
FirstEnergy Senior Transmission Management Team
FirstEnergy’s senior transmission management team is dedicated to the safe, reliable and
efficient delivery of electricity through the FirstEnergy Transmission System. These
individuals manage a dedicated full-time workforce of professional engineers, legal and
business personnel focused on the planning, construction, operation and maintenance of
the transmission system.
Charles E. Jones is Senior Vice President of FirstEnergy and President of FirstEnergy
Utilities, a business unit of FirstEnergy. He has responsibility for energy delivery,
customer service, compliance with FERC transmission requirements, and energy
efficiency activities, while leading FirstEnergy’s 10 utility operating companies and its
two stand-alone transmission companies.
Mr. Jones began his career with Ohio Edison as a substation engineer in 1978. He held a
variety of positions in the Akron, Marion and Elyria areas and, in 1995, was named
President of Ohio Edison’s Penn Power subsidiary. He returned to Akron in 1996 as
division manager.
Mr. Jones was subsequently named President of FirstEnergy’s Northern Region in 1997,
Vice President of Regional Operations in 2001, Senior Vice President of Energy Delivery
and Customer Service in 2003, and President, FirstEnergy Solutions Corp., in 2007. He
was named Senior Vice President, Energy Delivery and Customer Service, in 2009, and
elected to his current position in 2010.
Mr. Jones received a Bachelor of Science degree in Electrical Engineering from The
University of Akron. He also attended the United States Naval Academy for two years
and was a member of the Institute of Electrical and Electronics Engineers.
James R. Haney is Vice President, Compliance and Regulated Services, and Chief FERC
Compliance Officer for FirstEnergy Service Company, a subsidiary of FirstEnergy. Prior
9
to promotion to his current position, Mr. Haney served as President of FirstEnergy’s
West Virginia Operations.
Mr. Haney joined Allegheny Energy, Inc. (Allegheny) in 1978 as an engineer. Following
a series of promotions, he was named division manager in 1990. In 1996, he became
Director, Transmission Projects and was promoted in 1998 to Vice President, Customer
Operations. Mr. Haney was named Vice President, Transmission and Distribution, in
2003, prior to becoming Vice President, Transmission, in 2005. Upon the merger of
Allegheny into FirstEnergy, he was promoted to President of West Virginia Operations in
February 2011.
Mr. Haney received a Bachelor’s Degree in Electrical Engineering from West Virginia
University and is a Registered Professional Engineer. He serves as a director for the
West Virginia High Technology Consortium Foundation, Ohio Valley Electric
Corporation and ReliabilityFirst Corporation (RFC).
Carl Bridenbaugh is Vice President of Transmission for FirstEnergy Service Company.
In his current position, Mr. Bridenbaugh is responsible for transmission operations,
system planning and protection, transmission line and substation maintenance, asset and
project management and transmission substation and line design. He also is
FirstEnergy’s interface with transmission organizations such as NERC, PJM and RFC.
Mr. Bridenbaugh began his career with Ohio Edison Company, a FirstEnergy operating
company, in 1988 as a transmission planning engineer and has held positions in the
FirstEnergy organization as Manager, Transmission Planning and Director, Transmission
Operations. Prior to promotion to his current position, Mr. Bridenbaugh was Director of
Transmission Planning and Protection. Prior to joining Ohio Edison Company, he was an
application engineer with General Electric Company.
Mr. Bridenbaugh received a Bachelor’s Degree in Electrical Engineering from the
University of Detroit Mercy and a Master’s Degree in Electrical Engineering from Union
College. He is a Registered Professional Engineer in Ohio.
FirstEnergy Transmission Organization
The transmission function within FirstEnergy includes hundreds of highly skilled
professionals organized in the following key departments:





Asset and Project Management
Transmission and Substation Design
Transmission and Substation Services
Transmission Planning and Protection
Transmission Operations
10
(C)
Demonstrated experience of the entity or its affiliate,
partner, or parent company to develop, construct, maintain, and
operate transmission facilities. Including a list or other evidence
of transmission facilities previously developed regarding
construction, maintenance, or operation of transmission facilities
both inside and outside of the PJM Region.
Through a series of several strategic mergers and asset transactions over the past 15
years, the most recent of which was completed in February 2011, FirstEnergy has grown
its diverse and sizeable asset base. FirstEnergy is now uniquely positioned as the
nation’s largest contiguous electric system with complementary assets across its
generation, transmission and distribution operations. These assets are in a prime location
within PJM.
FirstEnergy’s vision is to be a leading regional energy provider, recognized for
operational excellence, outstanding customer service and a commitment to safety; the
choice for long-term growth, investment value and financial strength; and a company
driven by its leadership, skills, diversity and character of its employees.
Through the FirstEnergy Transmission Owners, FirstEnergy expects to invest
approximately $700 million over the next several years in transmission upgrades across
its five PJM Transmission Zones to help maintain system reliability following the
deactivation of several older coal-based power plants. These projects include
construction of a transmission line by ATSI from the Bruce Mansfield plant to a new
substation near Cleveland, Ohio.
Additionally, ATSI is building a new transmission operations facility in Akron, Ohio.
The center will feature advanced computer systems to monitor grid reliability across the
FirstEnergy Transmission System. Eventually, the transmission and substation
operations of several FirstEnergy utilities will be moved to the new transmission
operations facility to maximize efficiency.
FirstEnergy is also enhancing the reliability of the distribution system through targeted
investments in new technologies that provide greater information on system conditions
and customer usage. New features have been introduced, including an online 24/7 Power
Center and greater functionality on mobile devices that make it easier for customers to
stay informed when outages occur.
Asset and Project Management Department
FirstEnergy’s Asset and Project Management Department, comprised of transmission
specialists, schedulers, engineers and project and construction managers, have three main
responsibilities: 1) to develop and facilitate strategies and processes to maximize the
value of FirstEnergy's transmission and distribution assets; 2) to manage the process and
facilitate the development of FirstEnergy's transmission and distribution capital portfolio;
and 3) to provide project management and construction site management support for
FirstEnergy's capital projects. The Asset Management group is responsible for
developing asset strategies and processes including those associated with spare
equipment levels and total life-cycle analyses. Asset Management also manages Cascade
which is FirstEnergy's asset management system. The Project Management groups
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manage large transmission projects and work with each FirstEnergy Transmission Zone’s
project management to ensure capital projects are appropriately managed.
Transmission and Substation Design Department
The mission of the Transmission and Substation Design organization is to support
regional operations and bulk transmission on design and technical activities associated
with capital projects. Additionally, this group provides design and technical support on
projects associated with electricity delivery to retail customers and, upon request, for
projects undertaken by the generation business unit. This group also maintains
engineering and material schedules, coordinates equipment specification and evaluation,
drawing management, transmission system wireless communication attachment process
and the PJM transmission interconnection study process.
Transmission and Substation Services Department
FirstEnergy’s transmission and substation maintenance programs are designed to ensure
the reliability and integrity of transmission infrastructure and substation equipment to
safeguard employees and the public and to meet all state and federal regulatory
requirements. These programs include preventive maintenance and corrective
maintenance practices. Preventive maintenance is typically time and/or conditioned
based. Corrective maintenance is used to address equipment deficiencies that are
identified during or outside of a preventive maintenance program. All preventive
maintenance and corrective maintenance practices are based on accepted electric utility
practices, manufacturer’s specifications, NESC, ASTM, ANSI and IEEE standards,
Electric Power Research Institute Copper Book on power transformers, expertise from
FirstEnergy engineers, managers, supervisors and other subject matter experts in the
industry. Maintenance practices are designed to provide guidance to field personnel for
the maintenance and testing of transmission infrastructure and substation equipment and
to ensure compliance with federal and state regulations.
FirstEnergy utilizes a combination of manufacturer’s guidelines, utility industry
transmission benchmarking, condition assessment and reliability evaluations to determine
maintenance programs and intervals, and to determine when substation equipment should
be repaired or replaced. The expected remaining life of equipment, in addition to other
factors, is taken into consideration when determining whether to repair, replace or
refurbish equipment. FirstEnergy retains maintenance records and/or inspection results as
required by all federal and state regulations.
FirstEnergy engineers assigned to the Transmission and Substation Services Department
are responsible for commissioning infrastructure, equipment, relay and control
installations, which includes releasing these assets for service. In addition to
commissioning responsibilities, the Transmission and Substation Services Department
engineers participate in equipment failure investigations and system mis-operations.
Transmission Planning and Protection Department
The Transmission Planning and Protection Department is responsible for planning as well
as protecting the FirstEnergy Transmission System and associated sub-transmission
systems in the PJM footprint. This analysis ensures compliance with NERC, PJM and
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FirstEnergy reliability standards and criteria. Transmission Planning routinely performs
studies and makes system enhancement recommendations for transmission (i.e. the PJM
RTEP process) and sub-transmission system changes, new load connections and new
generation connections. Transmission Protection provides relay system requirements,
relay settings and operational event analysis for FirstEnergy transmission and subtransmission protection systems. The Transmission Planning and Protection Department
activities drive the FirstEnergy transmission capital budget. In support of these activities,
and by working with PJM and RFC, the Transmission Compliance and Models group is
responsible to develop and maintain load flow, short circuit and dynamic stability
models.
Transmission Operations Department
The Transmission Operations group operates three control centers with direct
responsibility for the operation of over 24,000 circuit-miles of transmission lines with
voltages ranging from 34.5 kV to 500 kV. The three control centers are staffed 24/7 by
84 NERC and PJM certified Transmission System Operators and Shift Supervisors.
FirstEnergy maintains a state-of-the-art Energy Management System (EMS) that allows
for the monitoring and control of the bulk electric system. FirstEnergy personnel have
experience in designing and managing data acquisition systems that are integrated into
the bulk transmission assets. These systems acquire data made available to FirstEnergy
transmission control centers and transmit FirstEnergy data to PJM to assist in its role as
Reliability Coordinator. The three control centers also utilize state-of-the-art large-screen
visualization, which affords the Transmission System Operators effective situational
awareness of the status of the FirstEnergy Transmission System.
FirstEnergy has been recognized as a NERC-approved continuing education provider and
maintains an internal training department dedicated to Transmission System Operator
training and credential maintenance. FirstEnergy Transmission Operations also
maintains a power network analysis engineering group responsible for the review and
support of real-time network analysis and EMS network model maintenance. FirstEnergy
is committed to a culture of compliance in its Transmission Operations Compliance and
Procedures group, which is responsible for procedure development and regulatory
compliance.
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(D)
Previous record of the entity or its affiliate, partner, or parent
company to adhere to standardized construction, maintenance
and operating practices
Standardized Construction Maintenance and Operation Practices
FirstEnergy’s transmission construction, maintenance and operation standards and
practices are currently publicly posted on the PJM website at: pjm.com/planning/designengineering/maac-to-guidelines.
The standards and practices documents posted at the above website are as follows:
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Transmission System Design Criteria
Substation Bus Configuration and Substation Design Requirements
Spare Equipment Philosophy
Design, Application, Maintenance and Operations Technical Requirements
Ratings Guides
Installation & Commissioning
Inspection, Testing and Acceptance
(E) Capability of the entity or its affiliate, partner, or parent
company to adhere to standardized construction, maintenance
and operating practices
FirstEnergy has a long history of proven adherence to all state, federal and industry
practices and requirements. FirstEnergy has well-established design standards across its
system for implementation of new and retro-fit projects. These standards are based on
industry, local, state and federal requirements in addition to good utility practice. These
standards are reviewed and revised on a regular basis. Additionally, FirstEnergy has
documented standards, and materials for timely emergency restoration following failures
of both substation and transmission line equipment. All identified project design solution
alternatives are thoroughly reviewed during the conceptual design layout period, and
include constructability review. FirstEnergy was involved in the creation and intent to
post the standard Technical Guidelines and Recommendations outlined in response to
part (D) above.
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(F)
Financial statements of the entity or its affiliate, partner,
or parent company. Please provide the most recent fiscal quarter,
as well as the most recent three fiscal years, or the period of
existence of the entity, if shorter, or such other evidence
demonstrating an entity’s current and expected financial
capability acceptable to the Office of the Interconnection
The following documents are provided either as websites (below) or as
appendices where the online information is not available:



(G)
Financial statements of FirstEnergy for 2010 through 2012
Financial statements of FirstEnergy for the quarter ending March 31, 2013
http://investors.firstenergycorp.com/phoenix.zhtml?c=102230&p=irolsec&control_selectgroup=3,4,5.
http://investors.firstenergycorp.com/phoenix.zhtml?c=102230&p=irol-ufi
Moody’s, Fitch and S&P rating agency reports
Commitment by the entity to execute the Consolidated
Transmission Owners Agreement, if the entity becomes a
Designated Entity.
All of the FirstEnergy Transmission Owners companies are signatories to the
Consolidated Transmission Owners Agreement (CTOA) and active participants in the
Transmission Owners Sector of PJM and the CTOA’s Administrative Committee, Legal
Issues Team and various working groups. The FirstEnergy Transmission Owners commit
to remaining signatories to the CTOA while they are transmission owning members of
PJM.
Met-Ed, JCP&L and Penelec were transmission owning members of PJM and signatories
to a predecessor transmission owners agreement prior to FERC’s designation of PJM as
an Independent System Operator and later as a Regional Transmission Organization.
Met-Ed, JCP&L and Penelec were members of the original PJM power pool and have
remained members of PJM as it has evolved over the past fifty-plus years. Mon Power,
Potomac Edison and West Penn Power, doing business as Allegheny Power, became
signatories to a predecessor transmission owners agreement on December 15, 2005.
Subsequently, Met-Ed, JCP&L, Penelec, Mon Power, Potomac Edison and West Penn
Power became signatories to the CTOA when it replaced the predecessor transmission
owner agreements. TrAILCo became a signatory to the CTOA on November 8, 2007
followed by ATSI becoming a CTOA signatory on December 17, 2009.
15
(H)
Evidence demonstrating the ability of the entity to address and
timely remedy failure of facilities.
The FirstEnergy Transmission Owners have a strong record of responding quickly and
safely to service interruptions. Most recently, this was demonstrated by FirstEnergy’s
response to Hurricane Sandy, which struck FirstEnergy’s service area on October 29,
2012. Sandy ranks as the most damaging weather event faced by FirstEnergy. By
comparison, Sandy disrupted service to nearly 2.6 million FirstEnergy customers which
is more customers than Hurricane Irene and the October 2011 snowstorm combined and
more than twice as many customers as the 2011 Summer derecho. By the time Sandy’s
wind and rains ceased and floodwaters receded, the super storm had crossed every state
served by the FirstEnergy.
Sandy’s hurricane-force winds and rains hammered FirstEnergy’s operating companies in
New Jersey, Pennsylvania and parts of Maryland. In addition, FirstEnergy service areas
in western Maryland and parts of West Virginia were blanketed with up to three feet of
snow and wind gusts of up to 80 mph. In Ohio, FirstEnergy’s service area along the Lake
Erie shoreline experienced high winds and rain.
FirstEnergy’s transmission and distribution utilities responded to the catastrophic
destruction caused by Sandy with the largest mobilization of crews, equipment, material
and support in FirstEnergy history. While the regional dispatch offices of FirstEnergy's
utilities directed local restoration efforts, FirstEnergy's emergency operations center in
Akron, Ohio, supported the overall service restoration effort.
More than 20,000 workers, comprised of FirstEnergy employees, other utility personnel
and contractors, joined the massive service restoration effort. Linemen, hazard
responders, damage assessors, and other service and support personnel were engaged in
restoring service to customers. Companywide, crews responded to more than
65,000 reports of lines down and other hazards. During the restoration effort,
approximately 20,000 damaged crossarms, 6,300 utility poles and 4,600 transformers
were replaced and 700 miles of wire hung. Overall, FirstEnergy's three customer contact
centers received 1.5 million outage calls, the most ever taken in a single service
restoration event.
In the face of many challenges, crews restored service to more than half of the affected
FirstEnergy customers within three days and two-thirds of customers within five days.
More than 95 percent of the affected FirstEnergy customers in Pennsylvania, Ohio, West
Virginia and Maryland had service restored within eight days of Hurricane Sandy coming
ashore. By day 13 over 95 percent of JCP&L’s customers had their service restored.
In addressing large-scale outages, securing outside utility crews, electrical contractors
and tree contractors can be challenging as utilities impacted by the storm are pursuing the
same pool of utility workers and support personnel. To bring in sufficient crews to tackle
the historic rebuild effort in a safe and timely manner, FirstEnergy worked with six
mutual-aid assistance groups, including Mid-Atlantic Mutual Assistance, the New York
Mutual Assistance Group, Southeastern Electric Exchange, Great Lakes Mutual
Assistance, Midwest Mutual Assistance and Western Region Mutual Assistance.
Additionally, the Dept. of Energy volunteered personnel and contractors from the
Bonneville Power Administration, Western Area Power Administration and
16
Southwestern Power Administration. In all, workers were recruited from more than
30 states and Canada, coming from as far away as Oregon and California.
As part of the restoration process, 13 helicopters flew about 10,000 miles to perform
aerial patrols on FirstEnergy’s transmission, sub-transmission and distribution systems.
Crews worked 16 hours with eight hours mandatory rest until the job was done. And,
despite challenging work conditions, no significant safety incidents occurred.
Effective communication with key state personnel was vital to the successful service
restoration effort. In New Jersey, JCP&L implemented its recently enhanced emergency
communications plan during Sandy, providing information updates to local officials, the
Board of Public Utilities (BPU), legislators and the governor, including participation in
twice-daily calls with the BPU president and governor. In Ohio, daily communications
were provided to the governor, the chairman of the Public Utilities Commission of Ohio,
and the mayor of Cleveland. In Pennsylvania, updates were provided to local officials,
the Public Utility Commission, the General Assembly and the governor's staff. In
Maryland, frequent status updates were provided to the governor and his administration’s
energy advisor, and included helicopter tours of storm-ravaged Garrett County to show
the extent of the damage to the electrical infrastructure.
FirstEnergy’s ability to have skilled resources available to restore transmission facilities
is measured by the industry standard of outage duration. FirstEnergy’s outage duration
was better than first quartile in four of the past six years (based on PJMs “2006-2012
Performance Metrics Comparison” report). 5
(I)
Description of the experience of the entity in acquiring rights of
way (ROW)
To address the right-of-way (ROW) requirements of the large FirstEnergy Transmission
System, FirstEnergy has a substantial full-time internal staff responsible for ROW
acquisition. The ROW group has personnel throughout the FirstEnergy transmission
zones with numerous ROW acquisition efforts underway at all times.
Presently, FirstEnergy has hundreds of millions of dollars in planned transmission
underway for 2013 for which the necessary ROW have been or are being acquired. This
follows an additional several hundred million dollars in transmission completed in 2012
for which substantial ROW acquisition also was required.
Additionally, FirstEnergy has the ability to exercise eminent domain in the states covered
by its transmission zones. The FirstEnergy ROW group has considerable experience
working within the eminent domain construct to timely effect construction of RTEP
projects. FirstEnergy also benefits from participation in the Midwest Utilities Real Estate
Managers group and other utility real estate professionals groups to standardize
procedures and to collaborate on real estate issues making the entire process more
efficient and more transparent.
5
For the two years that FirstEnergy did not meet this criteria, associated long-duration outages were
a result of the SF6 buss failure at Smithburg and, as noted above, the major storms that occurred across its
service territory in 2011.
17
Credit Opinion: FirstEnergy Corp.
Global Credit Research - 27 Feb 2013
Akron, Ohio, United States
Ratings
Moody's
Rating
Category
Outlook
Issuer Rating
Sr Unsec Bank Credit Facility
Senior Unsecured
Negative
Baa3
Baa3
Baa3
FirstEnergy Solutions Corp.
Outlook
Issuer Rating
Bkd Senior Unsecured
Stable
Baa3
Baa3
Baa3
Cleveland Electric Illuminating Company
(The)
Outlook
Issuer Rating
First Mortgage Bonds
Senior Secured
Senior Unsecured
Pref. Stock
Stable
Baa3
Baa1
Baa1
Baa3
Ba2
Jersey Central Power & Light Company
Outlook
Issuer Rating
Senior Secured MTN
Senior Unsecured
Pref. Stock
Negative
Baa2
(P)A3
Baa2
Ba1
Contacts
Analyst
Scott Solomon/New York City
William L. Hess/New York City
Phone
212.553.4358
212.553.3837
Key Indicators
[1][2]FirstEnergy Corp. (The)
(CFO Pre-W/C + Interest) / Interest Expense
(CFO Pre-W/C) / Debt
(CFO Pre-W/C - Dividends) / Debt
Debt / Book Capitalization
LTM 9/30/2012
3.7x
14%
10%
54%
2011 2010 2009
3.7x 4.1x 3.5x
14% 17% 16%
10% 13% 12%
53% 60% 62%
[1] All ratios calculated in accordance with the Global Regulated Electric Utilities Rating Methodology using Moody's
standard adjustments. [2] 2011 Financial metrics reflect the merger with Allegheny Energy effective on February
25, 2011.
Note: For definitions of Moody's most common ratio terms please see the accompanying User's Guide.
Opinion
Rating Drivers
Scale and diversity of rate regulated cash flows
Fairly supportive regulatory environments in multi-state service territories
Commitment to strengthen balance sheet of its unregulated business segment
Reduced financial flexibility due to Hurricane Sandy
Assertions of over-earning and criticism around service restoration could negatively influence JCP&L's rate case
More elevated risk profile than a vertically-integrated utility
Consolidated financial metrics weakly position company in Baa3 rating category
Corporate Profile
FirstEnergy Corp. (FE: Baa3, negative outlook) owns twelve regulated utilities that collectively serve 6 million
customers and an unregulated electric generating portfolio of approximately 18,000 megawatts located primarily in
the Midwest with a heavy concentration of nuclear and super-critical base load coal plants.
FE's regulated utilities consist of two FERC-regulated transmission-only utilities: American Transmission Systems,
Inc. (ATSI: Baa1, under review for possible downgrade) and Trans-Allegheny Interstate Line Company (TrAILCo:
A3, under review for possible downgrade) and 10 state-regulated utilities, all of which but one are electric
transmission and distribution (T&D) utilities.
Challenges confronting FE's regulated businesses includes controlling costs in face of flat distribution sales and
managing a credit supportive rate case outcome in a rate filing made by Jersey Central Power & Light Company
(JCP&L: Baa2, negative) in the wake of Hurricane Sandy. This case has the potential to be politicized due to
accusations of over earning as well as the company's request to recover significant storm-related costs.
FE's two primary unregulated subsidiaries are FirstEnergy Solutions, Inc. (FES: Baa3 senior unsecured, stable)
and Allegheny Energy Supply Company, LLC (AE Supply: Baa3 senior unsecured debt, stable). Their generating
capacity is connected to the PJM Power Pool. This portfolio includes super-critical coal-fired generation (8,176 MW
or 45% of the portfolio), nuclear generation (3,991 MW or 22%), sub-critical coal-fired generation (2,506 MW or
14%), gas-fired generation (1,745 MW or 10%) and renewable generation (1,658 MW or 9%).
The sales strategy of the company's non-regulated generating subsidiaries is asset-based, meaning that sales are
largely limited to its own electric production and are in market areas which can be served (i.e. hedged) with the
energy produced. FES is focused on selling at least 90% of its generation one-year forward to three key retail sales
channels primarily located within the footprint of its generation assets: industrial and large commercial customers
(referred to as direct sales); government aggregation (primarily residential and small business customers); and
Provider of Last Resort (PoLR) load requirements. FES' objective is to have no more than 10% of its generation
exposed to the spot wholesale power market at any time while maintaining a laddered 3-4 year hedging approach
to mitigate cash flow volatility.
That said, FE's non-regulated generating business is operating in a weak business environment driven by a
sluggish recovering economy and depressed power and natural gas prices. In an effort to improve FES and AE
Supply's positioning within its current rating category, FE has committed to reduce these combined entities' debt
by a minimum of $1.5 billion, or 20%, by year-end.
Rating Rationale
Moody's evaluates FE's consolidated financial performance relative to the Regulated Electric and Gas Utilities
rating methodology and the Unregulated Utilities and Power Companies methodology both of which were published
in August 2009. The emphasis, however, is on the regulated methodology to reflect the scale and scope of FE's
regulated operations and that cash flow up-streamed to FE is primarily derived from these operations.
As depicted in the grid below, FE's implied ratings under the regulated methodology is Baa3 compared to its
current Baa3 senior unsecured rating. The indicated ratings under the methodology considers FE's consolidated
financial performance based on a three-year historical average and a 12-18 month prospective basis.
FE's Baa3 senior unsecured rating is supported by the scale and diversification of the company's regulated T&D
subsidiaries, the regulatory supportiveness provided to these companies and steps taken by management to offset
a weak business environment, including a planned issuance of up to $300 million of common equity during 2013.
The negative outlook, however, reflects headwinds facing the consolidated entity, including increased debt levels,
weakened key financial metrics and reduced financial flexibility
DETAILED RATING CONSIDERATIONS
Large and diversified regulated utility platform
The merger with Allegheny Energy completed in February 2011 increased the scale and diversification of FE's
regulated businesses. FE owns twelve regulated utility subsidiaries that operate in six states with an aggregate
rate base of approximately $13 billion.
Utility subsidiaries include Ohio Edison (Ohio), Penn Power (which is owned by Ohio Edison and operates in
Pennsylvania), Cleveland Electric Illuminating (Ohio), Toledo Edison (Ohio), Jersey Central Power and Light (New
Jersey), Metropolitan Edison (Pennsylvania), Pennsylvania Electric Company (Pennsylvania and New York),
American Transmission System, Inc.(ATSI), West Penn Power Company (Pennsylvania), Monongahela Power
Company (West Virginia), The Potomac Edison Company (Maryland and West Virginia), and TrAILCo. TrAILCo's
primary asset is a 150-mile FERC-regulated transmission line that was energized in May 2011 and will be a solid
contributor of earnings and cash flow going forward.
With the exception of Monongahela Power Company, all of FE's regulated utility subsidiaries are fairly low-risk
transmission-only, distribution-only or transmission and distribution utilities (Monongahela is the only vertically
integrated utility).
Collectively, these regulated businesses accounted for more than 60% of FE's consolidated revenue,
approximately 80% of consolidated operating income and 65% of consolidated assets during the nine months
ended September 30, 2012. From a regulated electric delivery perspective, approximately 37% of total delivered
volumes is to customers in Ohio, 35% in Pennsylvania, 14% in New Jersey and the remainder to customers in
West Virginia and Maryland.
We view the diversity associated with the ownership of multiple utilities positively due to the insulation that benefits
the parent company from any unexpected adverse event or other negative development occurring at one of its
companies or with one of its state service territories.
FE's portfolio of regulated businesses provides financial support with strong predictable cash flows and up-stream
dividend support. It is our expectation that FE's regulated utility subsidiaries will provide FE parent with an
aggregate dividend equal to its annual dividend to shareholders through at least 2015. This strategy has been a
credit positive for FES and AE Supply, and a distinction from some peers, in that it has enabled the two
unregulated subsidiaries to retain all of their operating cash flow for internal investment.
Fairly supportive regulatory environments in multi-state service territory
As discussed in Moody's rating methodology for Regulated Electric and Gas Utilities, the credit supportiveness of
the regulatory framework under which a utility operates is a critical rating factor. Generally speaking, the regulatory
environments in Pennsylvania, Ohio, and New Jersey have been fairly predictable and supportive in granting
reasonable rate increases and cost-recovery mechanisms but somewhat less predictable in West Virginia and
Maryland. The regulatory frameworks provided by the FERC to ATSI and TrAILCo are considered strong.
Retail electric markets in FE's service territories in Ohio, Pennsylvania, New Jersey and Maryland are competitive
in terms of electricity supply. Consequently, all customer classes have the ability to choose their retail energy
supplier. FE's utilities' primary role in these states is the delivery of power to customers over their transmission
and distribution network and, in return, the collection of energy delivery charges regardless of a customer's choice
of electricity supplier. Because these utilities also have provider of last resort obligations (PoLR), they must provide
retail power to consumers in their respective service territory who have not chosen an alternative energy supplier.
The costs associated with POLR are fully passed through to the utility's customers with no meaningful financial
impact. Generally speaking, utilities operating in these states are provided an adequate opportunity to recover their
respective costs and earn an allowed return.
respective costs and earn an allowed return.
From the perspective of our rating methodology, the overall regulatory treatment that FE's regulated utilities receive
from the multiple jurisdictions in which they operate and their respective ability to earn costs is considered to be
adequate, scoring on average in the mid-Baa range. From a consolidated perspective, however, we notch
downward to reflect FE's exposure to unregulated cash flows. As such, FE maps to rating factors in the range of
high-Ba, low - Baa range for Factor 1: Regulated Framework and for Factor 2: Ability to Recover Costs and Earn
Returns.
Commitment to strengthen balance sheet of its unregulated business
FE's intention to reduce the consolidated debt at its unregulated businesses by a minimum of $1.5 billion, or
approximately 20% by year-end is a credit positive for FES/AE Supply and is expected to improve their positioning
within the Baa3 rating category. Specifically, we expect the reduced debt profile to allow FES/AE Supply to achieve
key financial metrics of CFO pre-W/C to debt and RCF to debt in excess of 18% and interest coverage in excess
of 4.5 times annually during the three-year period 2014-2016, levels we view as appropriate for the current rating
level.
The financial performance of these companies has been negatively impacted by a decline in electric demand, the
price paid for electricity in the Midwest and reduced capacity pricing levels. For example, in 2012, FE had originally
anticipated selling 104 TWh of unregulated power to retail channel customers at an average price of $58 MWh but
achieved 100 TWh at $56 MWh.
Proceeds from a proposed asset transfer and asset sales, both of which FE intends to close prior to year-end, are
to facilitate the debt reduction. To that end, FE filed a generation transfer request with the West Virginia Public
Service Commission that involved its vertically integrated Monongahela Power Company (MP: Baa3, stable)
acquiring AE Supply's 80% ownership in the Harrison Power Station at book value (approximately $1.2 billion) and
placing it into its rate base. The transfer would result in MP having sole ownership in the 1,984 megawatt fullyscrubbed coal plant. As part of the transaction, MP would sell its 8% ownership in the Pleasants Plant to AE
Supply. MP would fund the transaction with a combination of debt issuance and equity provided by FE which could
potentially net AE Supply $1.1 billion.
Separately, FE has announced its intention to sell up to 1,181MW's of pumped storage hydro generating capacity.
These generation assets include AE Supply's approximate 24% ownership (660MW's) in the 2,775 Bath County
Pumped Storage Hydro facility located in Virginia and FES' sole ownership of the 450 MW Pennsylvania-based
Seneca Pumped Storage Generating Station.
We would expect FE to issue common equity should the net proceeds from the above proposed transactions
result in less than $1.5 billion of debt reduction. In addition, FE has committed to issuing up to $300 million in
common equity in 2013.
Hurricane Sandy negatively impacted FE's financial flexibility
Moody's estimates that FE's consolidated adjusted debt at year-end 2012 stood at approximately $23 billion,
almost $1 billion more than previously expected and up from approximately $21.6 billion at year-end 2011. The
increase in consolidated debt levels was driven in part by damage caused by Hurricane Sandy which required debt
funding of the material restoration costs that has pressured FE's financial flexibility.
Total storm restoration costs associated with Sandy is currently estimated at $860M (JCP&L's share is $629M or
74% of total costs), of which approximately $485 million was paid out during 4Q12 and funded in large with shortterm debt. The remaining $375 million, which is reflected in working capital at year-end 2012, will also be funded
with short-term debt. Recently, JCP&L received a financing order from the New Jersey Board of Public Utilities
(BPU) for long-term debt issuance of up to $750 million to repay short-term debt incurred to fund storm restoration
costs. As a result, JCP&L's adjusted leverage will increase by approximately 30% relative to pre-Sandy levels
which has pressured its key financial metrics that have historically positioned the company firmly in the Baa2rating category.
Assertions of over-earning and criticism around service restoration could negatively influence JCP&L's rate case
In July 2012, the New Jersey Board of Public Utilities (BPU) requested JCP&L file a rate case utilizing a calendar2011 test year, including known adjustments, to assure that JCP&L's rates are just and reasonable. This request
was driven in part by assertions made by the New Jersey Division of Rate Counsel, who stated its belief that
JCP&L was earning an unreasonable return.
JCP&L was earning an unreasonable return.
Specifically, the Division of Rate Counsel cited an opinion that, using FERC Form 1 data, JCP&L had earned a
12.37% return on rate base in 2010. JCP&L responded to this petition stating that their achieved return on equity is
currently within a reasonable range (10.1% ROE for the twelve month period ended June 30, 2011).
Pursuant to BPU's request, JCP&L filed a rate case in November 2012, requesting a $31.5 million rate increase
based on an 11.5% ROE request and a 53.8% equity capital ratio. Prior to December 2012, JCP&L had not filed a
rate case in years; its last rate case was effective in 2005, when the BPU approved an order allowing a 9.75%
ROE. In February 2013, JCP&L included in its amended rate case recovery of Sandy-related storm costs. The
BPU is expected to issue its order late in fourth quarter 2013.
In our opinion, JCP&L is at increased regulatory risk due to the Division of Rate Counsel's claims that it had been
earning unreasonable returns and the criticism around service restoration efforts in the aftermath of Sandy. As
such, we see a potential for a rate case outcome that is credit negative.
Taking into consideration JCP&L's increased leverage profile, if the BPU were to order a rate reduction as part of
the current rate case or if the company is unable to recover its Sandy-related costs in a reasonable manner,
JCP&L's financial metrics would likely be severely pressured and the company could face a rating downgrade.
Because FE is highly dependent on JCP&L (we estimate that approximately 20% of total distributions received
from its utility subsidiaries in 2012 were sourced from JCP&L), a downgrade of JCP&L could potentially trigger a
downgrade of FE.
Consolidated cash flow coverage metrics weakly position FE in the Baa3 rating category
We estimate FE's consolidated key financial metrics to have weakened in 2012, with consolidated CFO pre-W/C
to debt of approximately 13%, retained cash flow to debt of 9% and interest coverage of 3.7 times, compared to
17%, 13% and 4.1 times in 2010, the year prior to its merger with Allegheny Energy, Inc. These estimated key
financial metrics for 2012 include the impact of Hurricane Sandy on FE's consolidated operating cash flows.
Excluding this impact, consolidated key financial metrics would have been only slightly lower than FE's 2011
financial performance of approximately 14.4% consolidated CFO pre-W/C to debt, 10.3% retained cash flow to
debt and 3.7 times interest coverage which positioned the company weakly in the Baa3 rating category.
From a key financial metric perspective, a holding company that owns regulated utilities should achieve CFO preWC to debt and retained cash flow to debt in the range 13-16% and 9-12%, respectively, to achieve a Baa3 rating.
Given FE's more elevated risk profile, we are the opinion that the company should achieve consolidated financial
metrics more toward the high-end of these ranges. As such, we believe FE will need to achieve key consolidated
financial metrics of CFO pre-WC to debt of at least 15%, retained cash to debt of 11% and interest coverage of 3.8
times on a sustainable basis to maintain its current rating.
Peer comparables for FE include, among others, Exelon Corporation (Exelon: Baa2, stable), Public Service
Enterprise Group (PSEG: Baa2, stable) and PPL Corporation (PPL: Baa3, stable). Key financial metrics for these
companies during the trailing twelve months ended September 30, 2012 included CFO pre-WC to debt and
retained cash flow to debt of 24% and 17%, respectively, at Exelon, 20% and 12% at PSEG and 16% and 13% at
PPL.
Liquidity
FE's near-term liquidity profile is considered adequate as the company appears to have sufficient liquidity to fund
its near-term requirements. FE had $61 million of consolidated cash at January 31, 2013 and the family had
access to approximately $3.3 billion in aggregate liquidity under various committed credit facilities totaling $5.6
billion.
FE parent does not have a commercial paper program. Its primary external source of liquidity is a 5-year $2.0
billion revolving credit facility due May 2017. In addition to FE, each of its regulated utility operating subsidiaries with
the exception of its transmission utilities are named co-borrowers with contractually defined sub-limits. Availability
under this facility as of January 31, 2013 was $776 million.
FirstEnergy Transmission, LLC (FET - not rated), the parent company of ATSI and TrAILCo, is party to a 5-year
$1.0 billion revolving credit facility due May 2017 (similarly, ATSI and TRAILCo are named co-borrowers). This
facility is fully drawn.
A money pool arrangement provides FE's regulated companies the ability to borrow from each other and the
holding company.
Lastly, $2.5 billion is available to FES and AE Supply under a separate syndicated revolving credit facility expiring in
May 2017 that is subject to separate borrowing sub-limits for each borrower. This facility is expected to remain
undrawn as a primary purpose is to provide contingent liquidity in the event of a credit event. Specifically, as part of
normal business activities, FES and to a lesser extent AE Supply enter into various agreements that contain
collateral provisions that are contingent upon its credit ratings or the occurrence of a "material adverse event." As
of December 31, 2012, FES and AE Supply's exposure under these collateral provisions under a "material adverse
event" was $628 million (AE Supply, $55 million), of which $427 million would be triggered by a credit rating
downgrade to Ba1 (AE Supply, $6 million). Given the size of FES\AYE Supply's credit facility, this potential collateral
requirement appears manageable.
Each revolving credit facility contains only one financial covenant, applicable to each listed borrower separately,
which is a requirement to maintain a consolidated debt to total capitalization ratio of no more than 65% (FET's
requirement is 70%). All borrowers were in compliance with this requirement as of December 31, 2012. Terms of
the syndicated revolving credit facilities include a representation that no material adverse change has occurred,
albeit only at the time of initial execution of the revolving credit agreement. Subsequent usage of the credit facilities
does not require such a representation.
FE had approximately $2.3 billion in consolidated short- term borrowings as of December 31, 2012. We expect the
company to reduce its short-term debt balances with proceeds from long-term offerings. Recently, JCP&L
received a financing order from the New Jersey Board of Public Utilities (BPU) for long-term debt issuance of up to
$750 million to repay short-term debt.
FE's anticipates generating approximately $3.2-$3.4 billion in cash flow from operations in 2013. Anticipated cash
outflows include $920 million for dividends, $2.4 billion for anticipated capital expenditures and $205 million for
nuclear fuel, suggesting a net cash shortfall in the range of $200-400 million. FE has committed to issuing up to
$300 million of common equity during 2013.
Rating Outlook
FE's rating outlook is currently negative and reflects headwinds facing the consolidated entity, including increased
debt, weakened key financial metrics and reduced financial flexibility.
What Could Change the Rating - Up
Upward rating pressure is unlikely absent a significant shift in the company's mix of regulated and unregulated
businesses or a material improvement in power prices. Nevertheless, financial ratios incorporating Moody's
standard adjustments that would be consistent with a upgrade would be a sustainable ratio of CFO pre-W/C to
debt in excess of 19% and CFO pre-W/C interest coverage of greater than 4.0x.
What Could Change the Rating - Down
To maintain its current ratings, we believe FE will need to achieve key consolidated financial metrics of CFO preWC to debt of at least 15%, retained cash to debt of 11% and interest coverage of 3.8 times on a sustainable
basis. These specific levels take into consideration FE's consolidated risk profile and the financial performance
and rating levels of its peers.
While these metrics appear attainable, to achieve them the company will likely need to have a constructive
regulatory outcome in New Jersey, sustain reductions to operating costs, increase sales from its unregulated
businesses and manage consolidated debt levels. Signs over the near-term that FE will be unable to meet these
criteria would likely result in a downgrade.
Rating Factors
FirstEnergy Corp. (The)
Regulated Electric and Gas Utilities Industry [1][2]
LTM
9/30/2012
Moody's
12-18
month
Forward
Factor 1: Regulatory Framework (25%)
Measure Score
a) Regulatory Framework
Forward
View* As
of
February
2013
Measure Score
Baa
Ba
Baa
Baa
A
Ba
A
Ba
Factor 2: Ability To Recover Costs And Earn Returns (25%)
a) Ability To Recover Costs And Earn Returns
Factor 3: Diversification (10%)
a) Market Position (10%)
b) Generation and Fuel Diversity (0%)
Factor 4: Financial Strength, Liquidity And Key Financial Metrics (40%)
a) Liquidity (10%)
b) CFO pre-WC + Interest/ Interest (3 Year Avg) (7.5%)
3.8x
Baa
Baa
c) CFO pre-WC / Debt (3 Year Avg) (7.5%)
d) CFO pre-WC - Dividends / Debt (3 Year Avg) (7.5%)
e) Debt/Capitalization (3 Year Avg) (7.5%)
14.6%
10.8%
55.5%
Baa
Baa
Ba
Baa
3.4xBaa
3.8x
13-16% Baa
9-12% Baa
54-58% Baa/Ba
Rating:
a) Indicated Rating from Grid
b) Actual Rating Assigned
Baa3
Baa3
Baa3
Baa3
* THIS REPRESENTS MOODY'S FORWARD VIEW; NOT THE
VIEW OF THE ISSUER; AND UNLESS NOTED IN THE TEXT DOES
NOT INCORPORATE SIGNIFICANT ACQUISITIONS OR
DIVESTITURES
[1] All ratios are calculated using Moody's Standard Adjustments. [2] As of 9/30/2012; Source: Moody's Financial
Metrics
© 2013 Moody's Investors Service, Inc. and/or its licensors and affiliates (collectively, "MOODY'S"). All rights reserved.
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Credit Opinion: American Transmission Systems, Incorporated
Global Credit Research - 08 Nov 2012
Akron, Ohio, United States
Ratings
Category
Moody's Rating
Outlook
Senior Unsecured
Stable
Baa1
Parent: FirstEnergy Corp.
Outlook
Issuer Rating
Senior Unsecured
Stable
Baa3
Baa3
Baa3
Contacts
Analyst
Phone
212.553.4358
212.553.3837
Key Indicators
[1]American Transmission Systems, Incorporated
LTM 6/30/2012 2011 2010 2009
4.9x 4.0x 6.4x 5.9x
22% 17% 23% 18%
17% -13% 13% 11%
42% 42% 50% 51%
standard adjustments.
Opinion
Rating Drivers
- Low business risk profile
- Supportive regulatory environment
- Solid financial profile
- Parent's policy of managing its subsidiaries as a consolidated system
Corporate Profile
American Transmission System, Incorporated (ATSI: Baa1 senior unsecured, stable), an operating subsidiary of
FirstEnergy Transmission, LLC (FET: not rated), is a FERC regulated transmission company ultimately owned by
FirstEnergy Corp. (FE: Baa3, Stable Outlook). ATSI owns high-voltage transmission facilities primarily in Ohio
including approximately 5,800 pole miles of transmission lines.
ATSI's principal business is providing transmission services to electric energy providers and power marketers for
which it receives a fee that is regulated by the Federal Energy Regulatory Commission (FERC). Operational
control of ATSI's transmission facilities transferred to PJM from the MISO in June 2011. The primary rationale for
the transfer was to align all of FE's transmission facilities in PJM.
ATSI was formed in 1998. In 2000, several of FE's regulated utilities (Ohio Edison Company, The Cleveland
Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Power Company) transferred their
transmission assets to ATSI. ATSI's has one long-term note outstanding: $400 million of 5.25% senior notes due
January 2022.
SUMMARY RATING RATIONALE
Moody's evaluates ATSI's consolidated financial performance relative to the Regulated Electric and Gas Utilities
rating methodology published in August 2009. ATSI's indicated rating as depicted in the grid below is A3 compared
to its Baa1 senior unsecured rating.
ATSI's Baa1 senior unsecured rating reflects its low business risk profile and the strong supportive regulatory
environment provided by the FERC that usually facilitates predictable cash flows and a solid financial profile. The
rating, however, is constrained by FE's policy of managing its subsidiaries as a consolidated system.
The most important drivers for ATSI's rating are as follows:
- Low risk business profile
ATSI's business plan is dedicated exclusively to the transmission of high voltage electricity and is considered to be
low risk. ATSI's assets are long lived, have relatively low operating risk and operate as a monopoly within its
service territory. ATSI bears no commodity price risk but has some exposure to transmission demand on its
system.
- Supportive regulatory environment provides steady, stable cash flows
As an independent transmission company, ATSI's rates are subject to regulation by the FERC. In order to
encourage the separation of transmission systems from the generation and sale of electricity, and to facilitate
greater investment in transmission infrastructure, the FERC has allowed independent transmission system
owners to earn incentive rates of return that tend to be above those allowed for regulated electric utilities. The
FERC currently allows ATSI to collect in its rates a 12.38% return on equity. Because the rate setting processes do
not require rate hearings at the state commission level or contested proceedings before regulators, and since they
work to ensure timely recovery, we generally consider revenues determined under this FERC regulatory
framework to be more stable and predictable than other regulated utility businesses. As a result, within the
framework of the Methodology, ATSI maps to a rating factor in the Aa range for Factor 1: Regulatory Framework.
ATSI's rates are established using a formulaic historical-looking cost-of-service model known as Attachment H,
which is recalculated annually and provides the utility the ability to recover increased or unexpected expenses in
future rates. While the formulaic rate setting mechanic generally provides assurance of cost recovery within a two
year period, it is still subject to challenge by interested parties including state regulators via a proceeding at the
FERC. Consequently, within the framework of the Methodology, ATSI maps to a rating in the A range for Factor 2:
Ability to Recover Costs and Earn Returns. Ongoing favorable regulatory support represents an essential factor in
ATSI's ability to maintain its financial strength.
- Customer concentration risk mitigated by PJM membership
More than 80% of ATSI's revenues are generated by providing transmission services to the FE affiliates that
previously owned the transmission assets. Although this increases ATSI's customer concentration risk, its status
as a member of PJM acts to limit the risk of non-payment. Specifically, while ATSI indirectly provides the bulk of its
transmission services to its affiliates, it bills PJM for its transmission services. In turn, PJM bills its members and
remits payment directly to ATSI. Losses at ATSI caused by non-payment are generally socialized amongst PJM
members, which is currently in excess of 800 in number.
FE's policy of managing its subsidiaries as a consolidated system tends to keep the ratings of FE's subsidiaries
closely aligned. FE and its subsidiaries commingle funds through a central managed money pool arrangement and
share management. Furthermore, the primary source for external liquidity for FE's regulated subsidiaries are $3B
of shared revolving credit facilities. That being said, ATSI's low business risk profile, supportive regulatory
environment and solid financial profile has resulted in a rating that is the highest in the FE family.
- Solid financial profile; near-term growth opportunities seen
ATSI's financial performance is expected to remain solid. Specifically, its key financial metrics of cash from
operation pre-working capital (CFO pre-W/C) to debt for the trailing twelve months ended June 30, 2012 was
approximately 22% and CFO pre-W/C interest coverage was approximately 5 times. ATSI's key financial metrics
over the are expected to remain in excess of 20% and 5 times, respectively.
FE sees considerable investment opportunities for transmission expansion projects. These opportunities are
concentrated within the footprint of the company's Ohio-based distribution utilities driven in part by FE's decision to
retire certain coal plants in this region. Specifically, FE sees the potential for $500-$700 million in transmission
related investments through 2016. We view investment in transmission positively due to the strong allowed return,
minimal construction risk and cash flow visibility. That said, we would expect the company to finance such
investments in a manner that supports its existing credit profile and would involve a combination of incremental
debt, and internal cash flow.
Liquidity
ATSI's sources of external liquidity include access to FE's regulated utility money and a $100 million committed
sub-limit under FET's five-year, $1.0 billion revolving credit facility maturing in May 2017 (ATSI and its affiliate
Trans-Allegheny Interstate Line Company are listed borrower under this facility). Prior to May 2012, ATSI was a
listed borrower under FE's $2 billion facility with the same $100 million committed sub-limit.
Under the terms of the regulated money pool, FE can only place money into the money pool while all its regulated
utilities can either place money into, or borrow from the money pool. The revolving credit facility contains only one
financial covenant, applicable to each listed borrower separately, which is a requirement to maintain a consolidated
debt to total capitalization ratio of no more than 65%. ATSI's ratio of consolidated debt to total capitalization at June
30, 2012, as defined under the credit facility, was 48.6%. Terms of the syndicated revolving credit facility include a
representation that no material adverse change has occurred, albeit only at the time of initial execution of the
revolving credit agreement. Subsequent usage of the credit facility does not require such a representation.
ATSI had no short-term debt outstanding at December 31, 2011 or June 30, 2012. We expect ATSI will continue to
pay a dividend to FE in an amount equal to 100% of earnings for at least 2012 and to be cash flow neutral through
2013.
Within the framework of the methodology, ATSI maps to a rating factor in the low Baa range for Factor 4 - Liquidity.
This rating is principally driven by ATSI's participation in a money pool administered by its lower-rated parent.
Rating Outlook
The stable outlook for ATSI reflects our expectation for continued setting of rates by the current formulaic method,
and CFO pre-W/C to debt and interest coverage in excess of 20% and 5 times, respectively.
An upgrade in the near-term seems unlikely. A significant increase in credit metrics, such as a ratio of CFO preWC to debt of greater than 26% on a sustainable basis or a more lucrative ROE and rate structure from the FERC
could be a trigger for upgrade. Upgrades at either FE or multiple subsidiaries could also have positive rating
implications.
ATSI could experience downward rate pressure if the FERC negatively changes the rate structure or if there is a
serious deterioration of credit metrics, such as a ratio of CFO pre-W/C to debt of below 16% on a sustainable
basis. A downgrade of FE or multiple FE subsidiaries could also have negative rating implications.
Rating Factors
American Transmission Systems, Incorporated
Current
12/31/2011
Measure Score
Moody's
12-18
month
Forward
View* As
of
November
2012
Measure Score
Aa
Aa
A
A
Baa
na
Baa
na
Factor 4: Financial Strength, Liquidity And Key Financial
Metrics (40%)
a) Liquidity (10%)
5.4x
19.7%
4.9%
47.9%
Baa
A
Baa
Ba
Baa
5.5-6.5x
22-26%
20-24%
40-45%
Baa
A
A
A
A
Rating:
A3
Baa1
A2
Baa1
* THIS REPRESENTS MOODY'S FORWARD VIEW; NOT THE
VIEW OF THE ISSUER; AND UNLESS NOTED IN THE TEXT
DOES NOT INCORPORATE SIGNIFICANT ACQUISITIONS OR
DIVESTITURES
Metrics
Any publication into Australia of this document is by MOODY'S affiliate, Moody's Investors Service Pty Limited ABN 61
003 399 657, which holds Australian Financial Services License no. 336969. This document is intended to be provided
only to "wholesale clients" within the meaning of section 761G of the Corporations Act 2001. By continuing to access this
2001.
Notwithstanding the foregoing, credit ratings assigned on and after October 1, 2010 by Moody's Japan K.K. (“MJKK”) are
MJKK's current opinions of the relative future credit risk of entities, credit commitments, or debt or debt-like securities. In
such a case, “MIS” in the foregoing statements shall be deemed to be replaced with “MJKK”. MJKK is a wholly-owned
credit rating agency subsidiary of Moody's Group Japan G.K., which is wholly owned by Moody’s Overseas Holdings Inc.,
a wholly-owned subsidiary of MCO.
This credit rating is an opinion as to the creditworthiness of a debt obligation of the issuer, not on the equity securities of
the issuer or any form of security that is available to retail investors. It would be dangerous for retail investors to make
any investment decision based on this credit rating. If in doubt you should contact your financial or other professional
adviser.
Credit Opinion: Trans-Allegheny Interstate Line Company
Global Credit Research - 15 Jan 2013
Greensburg, Pennsylvania, United States
Ratings
Category
Moody's Rating
Outlook
Issuer Rating
Senior Unsecured
Stable
A3
A3
A3
Ult Parent: FirstEnergy Corp.
Outlook
Issuer Rating
Senior Unsecured
Stable
Baa3
Baa3
Baa3
Contacts
Analyst
Phone
212.553.4358
212.553.3837
Key Indicators
[1]Trans-Allegheny Interstate Line Company
LTM 9/30/2012 2010 2009 2008
9.3x 5.3x 2.8x 4.5x
41% 20% 7%
6%
15% -2% 7%
6%
33% 42% 65% 66%
standard adjustments.
Opinion
Rating Drivers
- Low business risk profile
- Supportive regulatory environment
- Solid financial profile
Corporate Profile
Trans-Allegheny Interstate Line Company (TrAILCo: A3, Stable) is a transmission company that primarily
constructs, owns, operates, and maintains transmission assets located primarily within the PJM Interconnection.
TrAILCo's primary investment is Trans-Allegheny Interstate Line (TrAIL) a 500 kV transmission line that extends for
150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection in northern Virginia.
The project commenced construction in June 2006 and was completed and energized on May 19, 2011.
TrAIL accounts for approximately 90% of TrAILCo's rate base.
TrAILCo is an operating subsidiary of FirstEnergy Transmission, LLC (FET: not rated), and ultimately owned by
FirstEnergy Corp. (FE: Baa3, Stable). FET's other significant operating subsidiary is American Transmission
Systems, Incorporated (ATSI: Baa1, Stable). ATSI owns high-voltage transmission facilities primarily in Ohio
including approximately 5,800 pole miles of transmission lines.
The one-notch rating differential between TrAILCo and ATSI is driven by TrAILCo's stronger financial performance
and a modest difference in regulatory treatment. Specifically, TrAILCo files its annual revenue requirement based
on forward-looking costs while ATSI's is based on historical costs.
TrAILCo has one long-term note outstanding: $450 million of 4.0% senior notes due January 2015. It does not
currently anticipate a need for additional long-term debt.
SUMMARY RATING RATIONALE
Moody's evaluates TrAILCo's financial performance relative to the Regulated Electric and Gas Utilities rating
methodology published in August 2009. TrAILCo's indicated rating as depicted in the grids below is A2 compared to
its current A3 senior unsecured rating. TrAILCo's rating is constrained by its ownership by lower-rated FE. The
indicated grid ratings consider TrAILCo's consolidated financial performance based on a three-year historical
average and 18-24 month prospective basis.
TrAILCo's A3 senior unsecured rating reflects its low business risk profile; the strong supportive regulatory
environment provided by the FERC that usually facilitates predictable cash flows and strong expected financial
performance.
Recent Events
On January 3, 2012 via a letter, The Division of Audits in the Office of Enforcement (OE) at FERC announced that
it would be conducting an audit of TrAILCo. The audit is intended to evaluate whether TrAILCo has remained in
compliance with the conditions of its incentive rate treatments, the provisions of its formula rate and FERC's
accounting regulations. FE maintains that the audit is routine and is currently awaiting the FERC's findings.
The most important drivers for TrAILCo's rating are as follows:
- Supportive regulatory environment provides steady, stable cash flows
TrAILCo's rates are subject to regulation by the FERC. In order to facilitate greater investment in transmission
infrastructure, the FERC has allowed transmission system owners to earn incentive rates of return that tend to be
above those allowed for regulated electric utilities. The FERC currently allows TrAILCo to collect in its rates a
12.7% return on equity on for the TrAIL project and 11.7% on most other transmission projects.
TrAILCo's transmission revenue is determined through a FERC formula that allows for recovery of all prudently
incurred expenses and for a return on capital all prudently incurred capital costs. The revenue requirement, reset
annually, includes a return on rate base plus recovery of forward-looking depreciation, interest expense, income
taxes and operating and maintenance costs. TrAILCo typically files its annual revenue requirement with the FERC
in May for rates effective in June.
TrAILCo began collecting rates under its formula rate mechanism on June 1, 2007, and received payments for
100% of construction work in progress during the construction of TrAIL, earning a return on equity based on a
hypothetical capital structure of 50% debt and 50% equity during TrAIL's construction. The actual capital structure
was incorporated in the formula rate mechanism for 2012. TrAILCo's capital structure at September 30, 2012 was
60% equity and 40% debt.
Moody's observes that unlike state regulatory rate setting, FERC's formulaic rating setting process does not
require a rate hearing, suggesting that the revenue recovery will be more timely and predictable than other state
regulated utilities. For these reasons and for some of the characteristics embodied in the formula, Moody's
considers FERC regulation for electric transmission to be Aa for regulatory supportiveness and A for its cost
recovery mechanism.
That said, there has been some indications that the FERC may be contemplating in some instances a lowered
allowed return on equity for transmission investments. TrAILCo's rating could be downgraded if FERC noticeably
changes its revenue recovery framework.
- Low risk business profile
TrAILCo's transmission operation bears low business and operation risk, with a high barrier to entry. TrAILCo
receives all of its revenues from PJM on a monthly basis. PJM's diverse membership and legal structure ensures
low counterparty risk. PJM allocates each transmission owner's revenue requirement to the transmission zones
within the PJM region under FERC's direction. PJM determines an annual demand charge by dividing the total
revenue requirement allocated to a specific transmission zone by the annual system peak load and bills network
customers on monthly basis. Each member's obligation to PJM is joint and several. If one of the PJM participants
defaults on its payment to PJM, the defaulted amount is shared across all other participants.
- Well capitalized balance sheet
TrAILCo's capital structure at September 30, 2012 stood at approximately 60% equity and 40% debt. The sole
long-term debt outstanding is a $450 million senior unsecured note due 2015 and we expect TrAILCo to maintain
its current capital structure going forward.
TrAILCo will likely refinance its senior unsecured note with a similarly sized debt offering close to maturity.
- Continued strong financial metrics
TrAILCo's recent financial performance and key financial metrics have been exceptionally strong. Specifically, the
company's ratio of cash from operations before working capital changes to adjusted debt and interest coverage
during the twelve months ended September 30, 2012 was approximately 40% and 9 times, respectively compared
to 20% and 5 times, respectively, during the twelve months ended December 2011.
The primary driver for improved performance has been the impact of bonus depreciation, which largely negated
TrAILCo's tax obligation during this period. The impact of bonus depreciation, however, is non-recurring.
Regardless, we expect TrAILCo's near-term financial performance to remain consistent with a low A-rated
transmission company. Specifically, its ratio of cash from operations before working capital changes (CFO preW/C) to adjusted debt is expected to be at approximately 25% and interest coverage at 6.0 times through 2015.
FE sees considerable investment opportunities for transmission expansion projects. These opportunities are
concentrated within the footprint of the company's Ohio-based distribution utilities driven in part by coal plant
retirements in this region. Specifically, FE sees the potential for $700 million in transmission related investments
through 2016. The majority of this spend is expected to occur at ATSI. We view investment in transmission
positively due to the strong allowed return, minimal construction risk and cash flow visibility. That said, we would
expect the company to finance such investments in a manner that supports its existing credit profile and would
involve a combination of incremental debt, and internal cash flow.
FE's policy of managing its subsidiaries as a consolidated system tends to keep the ratings of FE's subsidiaries
closely aligned. FE and its subsidiaries commingle funds through a central managed money pool arrangement and
share management. That being said, TrAILCo's low business risk profile, supportive regulatory environment and
strong financial profile has resulted in a rating that is the highest in the FE family.
Liquidity
TrAILCo has generated strong internal cash flows since it achieved commercial operation in May 2011. During the
twelve months ended September 30, 2012, the company generated approximately $140 million of cash flow from
operations. This amount was used to fund capital expenditures totaling $40 million and to reduce short-term
borrowings from affiliates by approximately $100 million. Short-term debt was incurred in 2011 when TrAILCo
repaid amounts borrowed under a revolving credit facility to fund in part construction costs.
We anticipate TrAILCo will generate $130 million from operations in 2013. These funds will likely be used to fund
capital expenditures (estimated at $85 million) with the balance to be provided to FE in the form of a dividend.
TrAILCo's sources of external liquidity include access to FE's regulated utility money and a $200 million committed
sub-limit under FET's five-year, $1.0 billion revolving credit facility maturing in May 2017 (TrAILCo and ATSI are
listed borrowers under this facility).
Under the terms of the regulated money pool, FE can only place money into the money pool while all its regulated
utilities can either place money into, or borrow from the money pool. The revolving credit facility contains only one
financial covenant, applicable to each listed borrower separately, which is a requirement to maintain a consolidated
debt to total capitalization ratio of no more than 65%. TrRAILCo's ratio of consolidated debt to total capitalization at
September 30, 2012, as defined under the credit facility, was 40.5%. Terms of the syndicated revolving credit
facility include a representation that no material adverse change has occurred, albeit only at the time of initial
execution of the revolving credit agreement. Subsequent usage of the credit facility does not require such a
representation.
TrAILCo had $41 million of short-term debt borrowed from its affiliates as of September 30, 2012, reduced from
$145 million at year-end 2011. Borrowings from affiliates do not count against the revolving credit facility.
Within the framework of the methodology, TrAILCo maps to a rating factor in the low Baa range for Factor 4 Liquidity. This rating is principally driven by the company's participation in a money pool administered by its lowerrated parent.
Rating Outlook
The stable rating outlook for TrAILCo reflects our expectation that the company will generate cash from operations
prior to changes in working capital to debt in excess of 20% and positive free cash flow through 2015.
TrAILCo's current rating is capped at A3 due to its ownership by lower-rated FE as well as FE's policy of managing
its subsidiaries as a consolidated system. At this time, the prospects for an upgrade are limited. TrAILCo's rating
could only be upgraded if there is a significant positive change in FE's credit profile.
The rating could be downgraded if FERC noticeably changes its revenue recovery framework in a less favorable
fashion or if the company increases its leverage profile such that its metric of CFO pre-W/C to debt declines to
below 20% for an extended period of time. Additionally, if FE is downgraded, rating pressure on TrAILCo could
surface. As noted previously, FE's positioning within the Baa3 rating category has weakened.
Rating Factors
Trans-Allegheny Interstate Line Company
Current
12/31/2011
Measure Score
Moody's
12-18
month
Forward
View* As
of
January
2013
Measure Score
Aa
Aa
A
A
Baa
Baa
Factor 4: Financial Strength, Liquidity And Key Financial Metrics (40%)
a) Liquidity (10%)
4.1x
Baa
Baa
10.7%
3.8%
55.2%
Ba
Ba
Ba
Ba
5.9xAa
6.2x
24-26% Aa
12-14% Aa
35-40% A
A3
A3
A2
A3
Rating:
* THIS REPRESENTS MOODY'S FORWARD VIEW; NOT THE VIEW
OF THE ISSUER; AND UNLESS NOTED IN THE TEXT DOES NOT
INCORPORATE SIGNIFICANT ACQUISITIONS OR DIVESTITURES
Metrics
For Australia only: Any publication into Australia of this document is pursuant to the Australian Financial Services License
of MOODY'S affiliate, Moody's Investors Service Pty Limited ABN 61 003 399 657AFSL 336969 and/or Moody's Analytics
Australia Pty Ltd ABN 94 105 136 972 AFSL 383569 (as applicable). This document is intended to be provided only to
"wholesale clients" within the meaning of section 761G of the Corporations Act 2001. By continuing to access this
2001. MOODY'S credit rating is an opinion as to the creditworthiness of a debt obligation of the issuer, not on the equity
securities of the issuer or any form of security that is available to retail clients. It would be dangerous for retail clients to
professional adviser.
AMERICAN TRANSMISSION SYSTEMS, INCORPORATED
FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2011
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended
31,
(In thousands)
2011
$
OPERATING REVENUES
EXPENSES:
Operation and maintenance expenses
2010
204,992
$
54,364
Pensions and OPEB mark to market adjustments
(1,849)
38,840
Amortization of regulatory assets, net
General taxes
Total operating expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Miscellaneous income
37,471
5,369
9,857
30,804
129,512
29,688
136,863
75,480
104,214
2,529
Interest expense
739
(22,480)
Capitalized interest
241,077
61,696
135
Provision for depreciation
December
(21,827)
1,315
1,717
(18,636)
(19,371)
INCOME BEFORE INCOME TAXES
56,844
84,843
INCOME TAXES
17,294
28,365
Total other expense
NET INCOME
$
39,550
$
56,478
$
39,550
$
56,478
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs
Other comprehensive income (loss)
Income taxes (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
(103)
(103)
(165)
62
$
COMPREHENSIVE INCOME
39,612
(81)
(81)
666
(747)
$
55,731
The accompanying Notes to Financial Statements are an integral part of these financial statements.
1
BALANCE SHEETS
As of December 31,
2011
2010
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
ReceivablesAffiliated companies
Other
Notes receivable from affiliated companies
Prepayments and other
$
UTILITY PLANT:
In service
Less - Accumulated provision for depreciation
Construction work in progress
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets
Property taxes
Other
$
-
$
170,100
1,262
9,768
150,354
1,324
162,708
53,396
20,055
5,200
628
249,379
1,649,517
922,499
727,018
80,872
807,890
1,590,419
888,396
702,023
31,041
733,064
45,443
31,700
3,345
80,488
1,051,086
49,193
32,809
3,352
85,354
1,067,797
$
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Accounts payable to affiliated companies
Accrued taxes
Accrued MISO exit fee
Accrued Interest
Other
$
3,214
30,573
9,625
2,897
46,309
$
20,706
31,060
39,000
9,625
975
101,366
CAPITALIZATION:
Common stockholder's equity
Common stock, no par value, authorized 850 shares- 1 share outstanding
Other paid-in capital
Accumulated other comprehensive income
Retained earnings
Total common stockholder's equity
Long-term debt
NONCURRENT LIABILITIES:
Accumulated deferred income taxes
Accumulated deferred investment tax credits
Property taxes
Other
1
1
373,715
624
49,945
424,285
399,714
823,999
282,250
562
129,395
412,208
399,686
811,894
123,747
7,528
31,700
17,803
180,778
93,783
8,274
32,809
19,671
154,537
COMMITMENTS AND CONTINGENCIES
$
1,051,086
$
2
1,067,797
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(In thousands, except share amounts)
Balance, January 1, 2010
Common Stock
Number
Par
of Shares
Value
1
Other
Paid-In
Capital
1
Accumulated
Other
Comprehensive
Income
280,510
Net income
Pension and OPEB benefits, net
of $666 of income tax expense
Consolidated tax benefit allocation
Retained
Earnings
1,309
122,917
56,478
(747)
1,740
Cash dividends declared on common stock
Balance, December 31, 2010
(50,000)
1
1
282,250
562
129,395
Net income
39,550
Pension and OPEB benefits, net
of $165 of income tax benefits
Consolidated tax benefit allocation
62
465
Equity Infusion
91,000
(119,000)
1
$
1
$
373,715
3
$
624
$
49,945
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2011
2010
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash from operating activitiesProvision for depreciation
Amortization of regulatory assets, net
Pensions and OPEB mark-to-market adjustments
Deferred income taxes and investment tax credits, net
Pension trust contribution
MISO exit fee
Decrease (increase) in operating assetsReceivables
Prepayments and other current assets
Increase (decrease) in operating liabilitiesAccounts payable
Accrued taxes
Accrued Interest
Other
Net cash provided from operating activities
$
39,550
$
56,478
38,840
5,369
135
28,020
(3,000)
(39,000)
37,471
9,857
(1,849)
15,493
-
62,421
(696)
(48,054)
37
(17,492)
175
(552)
113,770
12,800
6,191
8,750
1,592
98,766
CASH FLOWS FROM FINANCING ACTIVITIES:
Equity infusion from parent
Common stock dividend payments
Other
Net cash used for financing activities
91,000
(119,000)
(359)
(28,359)
(50,000)
(217)
(50,217)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Loans to affiliated companies, net
Other
Net cash provided from (used for) investing activities
(107,822)
(145,154)
(2,535)
(255,511)
(64,333)
190,074
(4,190)
121,551
Net increase(decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
$
(170,100)
170,100
-
$
170,100
170,100
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid (received) during the yearInterest (net of amounts capitalized)
$
20,810
$
11,127
$
(39,138)
$
31,086
Income taxes
4
NOTES TO FINANCIAL STATEMENTS
Note
No.
1
2
3
4
5
6
7
8
9
Organization, Basis of Presentation and Significant Accounting Policies
Pension and Other Postemployment Benefits
Taxes
Leases
Capitalization
Short-Term Borrowings and Bank Lines of Credit
Regulatory Matters
Commitments and Contingencies
Transactions with Affiliated Companies
5
Page
No.
6
9
9
11
11
11
11
14
14
1. ORGANIZATION, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
American Transmission Systems, Incorporated (ATSI), is a wholly owned subsidiary of FirstEnergy Corp. (FirstEnergy). ATSI
follows accounting principles generally accepted in the United States (GAAP) and complies with the regulations, orders,
policies and practices prescribed by the Federal Energy Regulatory Commission (FERC). The preparation of financial
statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results
could differ from these estimates. The reported results of operations are not indicative of results of operations for any future
period. ATSI has evaluated events and transactions for potential recognition or disclosure through March 14, 2012.
ACCOUNTING FOR THE EFFECTS OF REGULATION
ATSI accounts for the effects of regulation through the application of regulatory accounting to its operating utilities since their
rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be
charged to and collected from customers.
ATSI records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded
under GAAP for non-regulated entities. These assets and liabilities are amortized in the Statements of Income concurrent with
the recovery or refund through customer rates. ATSI believes that it is probable that its regulatory assets and liabilities will be
recovered and settled, respectively, through future rates. ATSI nets its regulatory assets and liabilities.
Regulatory Assets Regulatory assets on the Balance Sheet are as follows:
2011
MISO Exit Fee Deferral (a)
Transmission Vegetation Management
Other
$
$
(a)
2010
(In thousands)
41,508 $ 39,000
5,275
3,935
4,918
45,443 $ 49,193
Comprised of recoverable MISO exit fees (See RTO Realignment below), which are not earning a current return.
REVENUES AND RECEIVABLES
ATSI's principal business is providing transmission service to electric energy providers, power marketers, and receiving
transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Receivables from
transmission customers include any electric utility (including transmission providers and power marketers), federal power
marketing agency, or person generating electric energy for sale or resale. There were no unbilled revenues or reserves related
to accounts receivable as of December 31, 2011 and 2010. There are 38 interconnections with six neighboring control areas.
ATSI's transmission system offers gateways into the East via high-capacity ties through Pennsylvania Electric Company
(Penelec), Duquesne Light Company (Duquesne) and West Penn Power Company; into the North through multiple 345 kV
high-capacity ties with Michigan's International Transmission Company and 138 kV through Cleveland Public Power; and into
the South through ties with American Electric Power Company, Inc. (AEP) and Dayton Power & Light.
PROPERTY, PLANT AND EQUIPMENT
ATSI owns high-voltage transmission facilities consisting of approximately 5,800 pole miles of transmission lines with nominal
voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission
facilities to the Midwest Independent Transmission System Operator, Inc. (MISO). On December 17, 2009, the FERC
authorized ATSI to transfer operational control of its facilities to the PJM Interconnection L.L.C. (PJM). On June 1, 2011, ATSI
successfully integrated into PJM.
Property, plant and equipment reflects original cost, including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance,
repairs and minor replacements are expensed as incurred. ATSI recognizes liabilities for planned major maintenance projects
as they are incurred.
ATSI provides for depreciation on a straight-line basis over the estimated lives of property included in plant in service. The
annual composite rate for ATSI's transmission facilities was approximately 2.4% in 2011 and 2010.
ATSI reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount
of such assets may not be recoverable. The recoverability of long-lived assets is measured by comparing the long-lived assets’
6
carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the
assets. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset an impairment exists and
a loss is recognized for the amount by which the carrying value of the long-lived assets exceeds their estimated fair value.
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on
the Balance Sheet at cost, which approximates their fair market value. Investments other than cash include notes receivable.
ACCUMULATED OTHER COMPREHENSIVE INCOME
The Accumulated Other Comprehensive Income (AOCI), net of tax, included on ATSI’s Balance Sheets as of December 31,
2011 and 2010, represents the net liability for unfunded pensions and other postemployment benefits (OPEB).
Other comprehensive income reclassified to net income in the two years ended December 31, 2011 is as follows:
Pensions and OPEB
Income taxes (benefits) related to reclassification
to net income
Reclassification to net income
2011
2010
(In thousands)
$
350 $
(427)
$
127
223 $
(155)
(272)
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
During the year, there have been various new accounting pronouncements that are not expected to have a material effect on
ATSI's financial statements.
CHANGE IN PENSIONS AND OPEB ACCOUNTING POLICY
Effective in 2011, ATSI elected to change its method of recognizing actuarial gains and losses for its defined benefit pension
and OPEB plans. Previously, ATSI recognized net actuarial gains and losses as a component of AOCI and amortized the gains
and losses into income over the remaining service life of affected employees within the related plans to the extent such gains
and losses were outside a corridor of the greater of 10% of the fair value of plan assets or 10% of the plans' projected benefit
obligation.
ATSI has elected to immediately recognize the change in the fair value of plan assets and net actuarial gains and losses
annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The
remaining components of pensions and OPEB expense, primarily service costs, interest on obligations, assumed return on
assets and prior service costs, will be recorded on a quarterly basis.
While ATSI's historical policy of recognizing pensions and OPEB expense was considered acceptable under GAAP,
FirstEnergy believes that the new policy is preferable as it eliminates the delay in recognizing gains and losses to earnings. The
change will also improve transparency to ATSI's operational results and benefits plan performance by immediately recognizing
deviations from expected actuarial assumptions in the year they are incurred.
This change in accounting policy has been applied retrospectively, adjusting all prior periods presented. Applying this change
retrospectively increased property, plant and equipment as a result of capitalizing a portion of the pension and OPEB costs now
recognized for each year in addition to additional depreciation expense. As a result of increasing those asset balances,
FirstEnergy recognized additional affiliated company asset transfers associated with ATSI and the Generation Asset Transfer,
and further impairments of certain long-lived assets in those periods. Additionally, the allocation of related pension and OPEB
costs from FESC and AESC to ATSI resulted in affiliated noncurrent liabilities as of December 31, 2011 of $17.3 million. The
impact of this accounting policy change on the financial statements is summarized below:
7
ATSI
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, 2010
As
Effect of
As
Reported
Change
Revised
61,374
322
61,696
(1,849)
(1,849)
37,332
139
37,471
1,635
82
1,717
83,373
1,470
84,843
28,470
(105)
28,365
54,903
1,575
56,478
(In thousands)
Operating costs
Income before income taxes
Income taxes
Net Income
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per share amounts)
Net Income
Pensions and OPEB,
Income taxes (benefits) on other comprehensive income
Comprehensive income
As
Effect of
As
Reported
Change
Revised
$
54,903
$
1,575
$
56,478
(612)
531
(81)
(226)
892
666
54,517
1,214
55,731
CONSOLIDATED BALANCE SHEETS
As of December 31, 2010
As
Effect of
As
Reported
Change
Revised
1,583,071
7,348
1,590,419
887,650
746
888,396
695,421
6,602
702,023
1,061,195
6,602
1,067,797
(2,714)
3,276
562
145,709
(16,314)
129,395
424,932
(12,724)
412,208
824,618
(12,724)
811,894
30,992
68
31,060
91,596
2,187
93,783
2,600
17,071
19,671
1,061,195
1,067,797
6,602
(In thousands)
Utility plant - in service
Accumlated provision for depreciation
Total property, plant, and equipment
Total assets
Accumulated other comprehensive income (loss)
Retained earnings
Total common stockholder's equity
Total capitalization
Accrued taxes
Other noncurrent liabilities
Total liabilities and capitalization
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(In thousands)
As
Effect of
As
Reported
Change
Revised
Retained EarningsBeginning Balance
$
140,806
$ (17,889)
$
122,917
Net Income
54,903
1,575
56,478
Ending Balance
145,709
(16,314)
129,395
Accumulated Comprehensive Income (Loss)Beginning Balance
Pension and OPEB, net of taxes
Ending Balance
$
(2,328)
(386)
(2,714)
$
3,637
(361)
3,276
$
1,309
(747)
562
CONSOLIDATED STATEMENTS OF CASH FLOW
(In thousands)
Net income
Deferred income taxes and investment tax credits, net
Other operating activities
As
Effect of
As
Reported
Change
Revised
54,903
1,575
56,478
37,332
139
37,471
15,636
(143)
15,493
(1,849)
(1,849)
1,314
278
1,592
98,766
98,766
8
2. PENSIONS AND OPEB
As described in Note 1, Organization, Basis of Presentation and Significant Accounting Policies, FirstEnergy elected to change
its method of recognizing actuarial gains and losses for its defined benefit pension plans and OPEB plans and applied this
change retrospectively to all periods presented.
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and
non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and
compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired
employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions,
deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain
circumstances, their survivors. FirstEnergy recognizes the expected cost of providing OPEB to employees and their
beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.
FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related
benefits.
FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During 2011,
FirstEnergy made pre-tax contributions to its qualified pension plans of $372 million ($3 million by ATSI). Pension and OPEB
costs are affected by employee demographics (including age, compensation levels and employment periods), the level of
contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key
assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in
determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date
for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement
date.
The following is a summary of the plan status:
Pensions
As of December 31,
FirstEnergy benefit obligation
FirstEnergy accumulated benefit obligation
ATSI Share of net liability
2011
$
7,977
7,409
-
OPEB
2010
$
2011
(in millions)
5,858
$
5,469
(2)
1,037
-
2010
$
861
(1)
3. TAXES
Income Taxes
ATSI records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax
effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the
amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences
are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are
recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the two years
ended December 31, 2011 are shown below:
PROVISION FOR INCOME TAXES:
2011
Currently payable(receivable)Federal
State
$
Deferred, netFederal
State
Investment tax credit amortization
Total provision for income taxes
$
2010
(In thousands)
(7,834)
(2,892)
(10,726)
27,161
1,605
28,766
(746)
17,294
$
$
11,451
1,421
12,872
16,194
45
16,239
(746)
28,365
ATSI is party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for
the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from
interest expense associated with acquisition indebtedness from FirstEnergy’s merger with GPU, is reallocated to the
subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company
receiving the tax benefit.
9
The following table provides a reconciliation of federal income tax expense at the federal statutory rate to the total provision for
income taxes for the two years ended December 31, 2011.
2011
2010
(In thousands)
Book income before provision for income taxes
$
56,844
$
84,843
Federal income tax expense at statutory rate
$
19,895
$
29,695
Increases (reductions) in taxes resulting fromAmortization of investment tax credits
(746)
State income taxes, net of federal income tax benefit
(837)
Effectively settled tax items
(746)
953
-
Interest from amended returns
(1,036)
(1,302)
Other, net
(29)
284
$
(472)
17,294
$
Accumulated deferred income taxes as of December 31, 2011 and 2010, are as follows:
2011
28,365
2010
(In thousands)
Property basis differences
$
Tax basis step-up
170,916
$
(58,337)
MISO exit fee deferral
(65,159)
14,160
Accrual for MISO exit fee
Unamortized investment tax credits
Deferred vegetation management costs
14,140
(654)
(14,140)
(2,733)
(3,000)
-
All other
1,913
395
Net accumulated deferred income tax liability
$
159,380
123,747
649
$
93,783
ATSI accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a
recognition threshold and measurement attributed for financial statement recognition and measurement of tax positions taken
or expected to be taken on a company’s tax return. After reaching settlement at appeals in 2010 related primarily to the
capitalization of certain costs for tax years 2004-2008, as well as receiving final approval from Joint Committee on Taxation,
ATSI recognized approximately $8.5 million of current net tax benefits in 2010 that were offset by deferred taxes, having no
impact to ATSI’s effective tax rate. ATSI’s unrecognized tax benefits as of December 31, 2011 and 2010, were immaterial.
ATSI recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the
applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or
expected to be taken on the tax return. ATSI includes net interest and penalties in the provision for income taxes. The reversal
of accrued interest associated with the recognized tax benefits noted above favorably affected ATSI’s effective tax rate by $1
million in 2010. The amount of net interest recognized during 2011 was immaterial.
In 2009, FirstEnergy filed a change in tax accounting method related to the costs to repair and maintain electric utility network
(transmission and distribution) assets. In 2010, approximately $325 million of costs ($3.5 million related to ATSI) were included
as a repair deduction on FirstEnergy’s 2009 consolidated tax return, which reduced taxable income and increased the amount
of tax refunds that were applied to FirstEnergy’s 2010 estimated federal tax payments. There was no impact on ATSI’s
effective tax rate. The IRS issued guidance in 2011 providing a safe harbor method of tax accounting for electric transmission
and distribution property to determine the tax treatment of repair costs for electric transmission and distribution assets. ATSI is
evaluating the method change for this temporary tax item and, if elected, it is not expected to be material to ATSI’s financial
position or effective tax rate.
ATSI has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax
returns for all state jurisdictions are open from 2007-2010. The IRS completed its audit of tax year 2008 in July 2010 and tax
year 2009 in April 2011. Tax years 2010-2011 are under review by the IRS. Management believes that adequate reserves have
been recognized and final settlement of these audits is not expected to have a material adverse effect on ATSI’s financial
condition, results of operations, cash flows or liquidity.
10
General Taxes
Details of general taxes for the two years ended December 31, 2011, are shown below:
2011
2010
(In thousands)
Real and personal property
Social security and unemployment
Other
Total general taxes
$
30,377
278
149
$
29,354
264
70
$
30,804
$
29,688
4. LEASES
ATSI leases fee-owned land, easements, franchises, and other land use rights from Ohio Edison Company (OE), Pennsylvania
Power Company (Penn), The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company (TE). Land use
is rented to ATSI under the terms and conditions of a ground lease approved by FERC. ATSI, OE, Penn, CEI, and TE reserve
the right to use (and to permit authorized others to use) the land for any purpose that does not cause a violation of electrical
safety code or applicable law, or does not impair ATSI's ability to satisfy its service obligations. Additional uses of such land for
ATSI's facilities requires prior written approval from the applicable operating companies. ATSI purchases directly any new
property acquired for transmission use. ATSI makes fixed quarterly lease payments of approximately $5.3 million through
December 31, 2049, unless terminated prior to maturity, or extended by ATSI for up to ten additional successive periods of fifty
years each.
5. CAPITALIZATION
Long-Term Debt On December 15, 2009, ATSI issued $400 million of 5.25% senior notes with a maturity date of January 15, 2022. The fair
value of long-term debt as of December 31, 2011 and 2010, was $436 million and $418 million, respectively.
Retained Earnings ATSI currently has no restrictions on its retained earnings available to pay common stock dividends.
6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
ATSI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements.
FirstEnergy Service Company (FESC) administers this money pool and tracks surplus funds of FirstEnergy and its regulated
subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available
through the pool. The average interest rate for short-term borrowings was 0.44% and 0.51%, in 2011 and 2010, respectively.
ATSI had investments in the money pool of $150 million and $5 million as of December 31, 2011 and, 2010, respectively.
An aggregate amount of $2 billion is available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility),
subject to separate borrowing sublimits for each borrower. The borrowers under the FirstEnergy Facility are FE, OE, Penn, CEI,
TE, Met-Ed, ATSI, JCP&L, MP, Penelec, PE and WP. Commitments under the FirstEnergy Facility will be available until
June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year
extensions. Generally, borrowings under the FirstEnergy Facility are available to each borrower separately and mature on the
earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. ATSI has
regulatory authority to borrow up to $100 million under the facility.
7. REGULATORY MATTERS
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, recordkeeping and reporting requirements on ATSI. The North American Electric Reliability Corporation (NERC), as the Electric
Reliability Organization (ERO) is charged with establishing and enforcing these reliability standards, although it has delegated
day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirst
Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. ATSI actively participates in the NERC
and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its assets in response to the ongoing
11
development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirst
Corporation.
ATSI believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in
the course of operating its extensive electric utility systems and facilities, ATSI occasionally learns of isolated facts or
circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, ATSI
develops information about the item and develops a remedial response to the specific circumstances, including in appropriate
cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirst and the FERC will continue
to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of
complying with new or amended standards cannot be determined at this time; however, 2005 amendments to the Federal
Power Act (FPA) provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still,
any future inability on ATSI’s part to comply with the reliability standards for its bulk power system could result in the imposition
of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
PJM Transmission Rate
In April 2007, FERC issued Opinion 494 order finding that the PJM transmission owners' existing “license plate” or zonal rate
design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained.
On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at
500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp
rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than
500 kV, however, are to be allocated on a load flow methodology, which is generally referred to as a “beneficiary pays”
approach to allocating the cost of high voltage transmission facilities.
FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in
August 2009. The court affirmed FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not
supported its decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on
this finding, remanded the rate design issue to FERC.
In an order dated January 21, 2010, FERC set the matter for a “paper hearing” and requested parties to submit written
comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed
PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then
reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM's
filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain
load serving entities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May
28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state
commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities.
Other utilities and state commissions supported continued socialization of these costs on a load ratio share basis. This matter is
awaiting action by FERC. FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational
or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.
On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM's
tariffs. On April 1, 2011, the MISO TOs (including ATSI) filed proposed tariff language that describes the mechanics of
collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy,
PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1,
2011. These filings include amendments to the MISO's tariffs (to remove the ATSI zone), submission of load and generation
interconnection agreements to reflect the move into PJM, and submission of changes to PJM's tariffs to support the move into
PJM.
On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs
that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI's
proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of
the MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a
cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such
move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI's
proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI
submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI's
proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit
analysis as part of FERC's evaluation of ATSI's proposed transmission rates. Finally, and also on June 30, 2011, the MISO and
the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction
and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to
ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other, have submitted subsequent filings - each
12
of which is intended to refute the other's claims. ATSI's compliance filing and request for rehearing, as well as the pleadings
that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC. Although the ultimate
outcome of this matter cannot be determined at this time, ATSI expects that it will fully recover the approximately $41.5 million
in deferred MISO exit fees.
From late April 2011 through June 2011, FERC issued other orders that address ATSI's move into PJM. Also, ATSI and the
MISO were able to negotiate an agreement of ATSI's responsibility for certain charges associated with long term firm
transmission rights that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did
not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated
with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted
for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to
ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.
MISO Multi-Value Project Rule Proposal
In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology
for certain new transmission projects. The new transmission projects--described as MVPs - are a class of transmission projects
that are approved via the MTEP. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge
that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through”
the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that
the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest
to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010,
MISO's Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP
projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue
to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be
allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO's proposal to allocate costs of MVPs
projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost
causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the
ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI.
Numerous other parties filed pleadings on MISO's MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. Despite being presented
with the issue by FirstEnergy and the MISO, the FERC did not address clearly the question of whether the MVP costs would be
payable by ATSI or load in the ATSI zone. FERC stated that the MISO's tariffs obligate ATSI to pay all charges that attached
prior to ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone
were beyond the scope of FERC's order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy requested rehearing of FERC's order. In its rehearing request, FirstEnergy argued that
because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that
does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of
allocating costs to the ATSI zone or to ATSI. On October 31, 2011, FESC filed a Petition of Review for the FERC's December
2010 and October 21, 2011 orders with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those
orders and, in November, 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the
Seventh Circuit. On January 27, 2012, the court ordered the FERC to file a proposed briefing format and schedule on or before
March 20, 2012.
On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 20, 2010 ruling. In the complaint,
FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP
responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011,
MISO, its TOs and other parties, filed responsive pleadings. MISO and its TOs argued that liability to pay for a single MVP
project (the Michigan Thumb Project) attached to ATSI, before ATSI was able to exit MISO, and argued that FERC should
order ATSI to pay a pro rata amount of the Michigan Thumb Project costs. On September 19, 2011, ATSI filed an answer
stating its view that there are no legal or factual bases to charge the Michigan Thumb Project costs to ATSI. The complaint, and
all subsequent pleadings, are pending before FERC.
On December 29, 2011, the MISO and the MISO TOs filed a new “Schedule 39” to the MISO's tariff. Schedule 39 purports to
establish a process whereby the MISO would bill TOs for MVP costs that, according to the MISO, attached to the utility prior to
such TOs withdrawal from the MISO. In its filing, the MISO identifies ATSI as a Transmission Owner that is responsible for the
MVP charges associated with the “Michigan Thumb” project and, on that basis, explained that the MISO would start billing the
Michigan Thumb project costs for the 2012 formula rate year to ATSI, beginning in February 2012.
On January 19, 2012, FESC filed a protest to the MISO's attempt to charge MVP costs to ATSI under the new Schedule 39
tariff. In the protest, FESC argued, among other things, that the MISO has failed to demonstrate that ATSI or the ATSI zone
customers will benefit from construction and operation of the Michigan Thumb Project. FESC further argued that the
13
Transmission Owners Agreement provides that ATSI is to pay any obligations that it owes upon exit from the MISO; but the
contractual language does not impose an obligation to pay MVP charges on ATSI and therefore does not authorize the MISO
or the MISO TOs to create new obligations that are to be charged to ATSI after ATSI's exit from the MISO. Finally, FESC
argued that the “filed rate” doctrine does not permit MISO and the MISO TOs to file a new rate for the purpose of collecting the
Michigan Thumb project costs from ATSI at a point in time that is more than seven months after ATSI withdrew from the MISO.
Various other parties, including Duke and the Public Utilities Commission of Ohio also filed protests. On February 3, 2012, the
MISO and the MISO TOs filed motions for leave to answer and answer to the protests, including FESC's.
FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.
8. COMMITMENTS AND CONTINGENCIES
ATSI accrues environmental and legal liabilities only when it concludes that it is probable that it has an obligation for such costs
and can reasonably estimate the amount of such costs. In cases where ATSI determines that it is not probable, but reasonably
possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate
can be made. If it were ultimately determined that ATSI or its subsidiaries have legal liability or are otherwise made subject to
liability based on any of the matters referenced above, it could have a material adverse effect on ATSI’s or its subsidiaries'
financial condition, results of operations and cash flows. Unasserted claims are reflected in ATSI’s determination of
environmental and legal liabilities and are accrued in the period that they are both probable and reasonably estimable.
9. TRANSACTIONS WITH AFFILIATED COMPANIES
In addition to the intercompany income tax allocation and short-term borrowing arrangement, ATSI has other operating
expense and interest expense transactions with affiliated companies, primarily OE, CEI, TE, Penn and FESC. The primary
affiliated-company transactions, including the effects of the transmission arrangements with OE, CEI, TE, and Penn, are as
follows:
2011
2010
(in millions)
Operating Costs:
Ground lease expense
Service Company support services
Interest expense
$21
$22
1
$ 21
26
1
FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to ATSI from FESC,
a subsidiary of FirstEnergy. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are
for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are
allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include
multiple factor formulas: each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees,
asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes
that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are
generally settled under commercial terms within thirty days.
14
TRANS-ALLEGHENY INTERSTATE LINE COMPANY
FINANCIAL STATEMENTS
FOR THE PERIODS JANUARY 1, 2011 THROUGH FEBRUARY 24, 2011, FEBRUARY 25,
2011 THROUGH DECEMBER 31, 2011 AND THE YEAR ENDED DECEMBER 31, 2010
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Successor
February 25,
2011
through
December
31, 2011
(In thousands)
REVENUES
Predecessor
January 1, 2011
through
February 24,
2011
Year ended
December 31,
2010
$169,762
$28,255
$137,043
12,307
20,611
2,416
2,561
1,022
276
13,070
5,132
2,004
35,334
3,859
20,206
OPERATING INCOME
134,428
24,396
116,837
OTHER INCOME (EXPENSE):
Interest expense
Other income, net
(22,681)
267
-
(5,958)
233
(29,899)
2,430
Total other expense
(22,414)
(5,725)
(27,469)
112,014
18,671
89,368
42,759
7,856
35,027
$69,255
$10,815
$54,341
OPERATING EXPENSES:
Operation and maintenance expenses
General taxes
Total operating expenses
INCOME BEFORE INCOME TAXES
INCOME TAXES
NET INCOME AND COMPREHENSIVE INCOME
1
BALANCE SHEETS
Successor
December
31, 2011
(In thousands)
Predecessor
December
31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
ReceivablesAffiliated companies
Other
Taxes receivable
Prepaid taxes
Regulatory assets
Deferred tax assets
Other
PROPERTY, PLANT AND EQUIPMENT:
In service
Less - Accumulated provision for depreciation
Construction work in progress
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets
Unamortized debt expense
Other
$8,897
$50,198
95
13,782
5,200
65,740
788
13,088
14,095
2,267
60,085
161
94,502
139,894
1,270,801
14,838
283,560
7,533
1,255,963
24,821
276,027
903,717
1,280,784
1,179,744
114,025
4,958
-
28,292
7,882
4,266
118,983
40,440
$1,494,269
$1,360,078
2
BALANCE SHEETS (Continued)
Successor
Predecessor
December
31, 2011
December
31, 2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Accounts payableAffiliated companies
Other
Short-term borrowings – affiliated companies
Accrued taxes
Accrued interest
Other
CAPITALIZATION:
Common stockholder’s equityCommon stock, $1 par value, 5,000 shares authorized and 1,000 shares
outstanding
Other paid-in capital
Retained earnings
Total Common Stockholder’s equity
Long-term debt and other long-term obligations
NONCURRENT LIABILITIES:
Regulatory liabilities
Other
$13,511
20,472
145,022
5,268
8,300
1,113
$4,752
45,346
23,196
3,210
10,288
3,709
193,686
90,501
1
646,632
19,255
1
318,962
97,575
665,888
457,950
416,538
818,633
1,123,838
1,235,171
170,804
5,941
31,557
823
2,026
176,745
34,406
$1,494,269
$1,360,078
COMMITMENTS AND CONTINGENCIES (Note 8)
3
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Common Stock
Shares
Outstanding Par Value
Predecessor:
Balance, January 1, 2010
Other
paid-in
capital
Retained
earnings
1,000
$1
$179,928
$43,233
-
-
139,000
34
-
54,341
1
Net income
1,000
-
$1
-
$318,962
-
$97,575
10,815
Balance, February 24, 2011
1,000
$1
$318,962
$108,390
-
-
1,000
$1
Net income
Parent company contribution
Stock-based excess tax benefits
Other
Successor:
Purchase accounting adjustments
Parent company contribution
Cash dividends as return of capital
Net income
107,670
300,000
(80,000)
$646,632
4
(108,390)
(50,000)
69,255
$19,255
STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash from operating
activities:
Deferred income taxes
Uncollected transmission revenue
Pensions and OPEB mark-to-market adjustment
Decrease (increase) in operating assetsAccounts receivable
Prepaid taxes
Other current assets
Increase (decrease) in operating liabilitiesAccounts payable
Accrued taxes
Accrued interest
Other
Successor
Predecessor
February 25,
2011 through
December 31,
2011
January 1, 2011
through
Year ended
February 24, December 31,
2011
2010
$69,255
$10,815
$54,341
20,611
53,133
(37,727)
1,635
1,022
(1,587)
(3,625)
-
5,132
26,625
(32,502)
-
(1,571)
(4,945)
(77)
782
145
(8,399)
(1,047)
-
7,001
6,708
5,173
6,642
1,520
9,462
(7,161)
736
(7,575)
11,407
9,210
256
125,838
12,109
57,448
10,000
(380,000)
145,022
300,000
(130,000)
(234)
-
837,661
(485,000)
(3)
139,000
34
(55,212)
(3)
491,695
(80,175)
(43,858)
(510,669)
(80,175)
(43,858)
(510,669)
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
(9,549)
18,446
(31,752)
50,198
38,474
11,724
Cash and cash equivalents at end of period
$8,897
$18,446
$50,198
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing - long-term debt
Redemptions and repayments - long-term debt
Short-term borrowings – affiliated companies
Parent company equity contribution
Common stock dividend payments
Other
Net cash provided from (used for) financing activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Cash used for investing activities
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid (received) Interest (net of amounts capitalized)
Income taxes
$13,032
$(14,857)
$12,086
$(169)
5
$15,161
$(981)
NOTES TO FINANCIAL STATEMENTS
Note
No.
Page
No.
1
2
3
4
5
6
7
8
9
7
9
9
12
12
12
13
13
13
Organization, Basis of Presentation and Significant Accounting Policies
Merger
Taxes
Intangible Assets
Fair Value Measurements
Debt and Credit Facilities
Regulatory Matters
Commitments and Contingencies
Transactions With Affiliated Companies
6
NOTES TO FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Trans-Allegheny Interstate Line Company (TrAIL) is a wholly owned indirect subsidiary of Allegheny Energy, Inc.
(AE). Effective February 25, 2011, AE became a wholly owned subsidiary of FirstEnergy Corp. (FirstEnergy), a
public utility holding company (See Note 2, Merger, for additional information). TrAIL was formed to construct,
manage and finance transmission expansion projects, including a 500 kV transmission line from southwestern
Pennsylvania through West Virginia and into Virginia (TrAIL Line). All segments of the TrAIL Line were energized and
placed into service on May 19, 2011.
TrAIL is subject to regulation by the Federal Energy Regulatory Commission (FERC).
Allegheny Energy Service Corporation (AESC), a wholly owned subsidiary of AE and FirstEnergy Service Company
(FESC), a wholly owned subsidiary of FirstEnergy are service support companies that employ FirstEnergy’s
personnel who provide services to TrAIL and other FirstEnergy subsidiaries.
PREDECESSOR AND SUCESSOR REPORTING AND FINANCIAL STATEMENT PRESENTATION
In connection with the merger, FirstEnergy acquired all of the outstanding common stock of AE. The merger has
been accounted for under the purchase method of accounting with FirstEnergy treated as the acquirer for accounting
purposes. Accordingly, the assets and liabilities of AE were recorded at their fair values as of the merger
consummation date. Purchase accounting impacts have been “pushed down” to AE and TrAIL, resulting in the
assets and liabilities of TrAIL being recorded at their respective fair values as of February 25, 2011 (See Note 2,
Merger, for additional information).
The financial statements subsequent to the merger include amortization relating to purchase accounting adjustments
and reflect reclassifications as of the merger date of retained earnings to other paid-in-capital and accumulated
depreciation to property, plant and equipment. In addition, TrAIL has conformed its accounting policies to those of
FirstEnergy as of the merger date, including policies relating to the capitalization of overhead charges. TrAIL’s
financial statements and certain notes separately present TrAIL’s financial information in two distinct periods, the
period before the consummation of the merger (labeled Predecessor) and the period after that date (labeled
Successor), because of the application of a different basis of accounting between the periods presented.
TrAIL follows accounting principles generally accepted in the United States of America (GAAP). The preparation of
financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and
liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of
results of operations for any future period. In preparing the financial statements, TrAIL has evaluated events and
transactions for potential recognition or disclosure through March 14, 2012, the date the financial statements were
issued.
ACCOUNTING FOR THE EFFECTS OF REGULATION
TrAIL accounts for the effects of regulation through the application of regulatory accounting since its rates are
established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be
charged to and collected from customers.
TrAIL records regulatory assets and liabilities that result from the regulated rate-making process that would not be
recorded under GAAP by non-regulated entities. These assets and liabilities are amortized in the Statements of
Income concurrent with their recovery or refund through customer rates. TrAIL believes that it is probable that its
regulatory assets and liabilities will be recovered and settled, respectively, through future rates.
7
Net regulatory assets on the Balance Sheets are comprised of the following:
(In millions)
Successor
Predecessor
December
31,
2011
December
31,
2010
Transmission revenue requirement under-collection ......................................................
Receivable from customers for future income taxes .......................................................
Loss on reacquired debt..................................................................................................
Asset removal costs ........................................................................................................
Other ...............................................................................................................................
$102.0
3.1
6.6
(6.7)
9.0
$74.5
4.0
9.9
(0.8)
-
Net regulatory assets ......................................................................................................
$114.0
$87.6
REVENUES AND RECEIVABLES
Under a formula rate mechanism approved by the Federal FERC, TrAIL makes annual filings in order to recover
incurred costs and an allowed return. An initial rate filing is made for each calendar year using estimated costs, which
is used to determine the initial billings to customers. All prudently incurred allowable operation and maintenance
costs, a return earned on rate base and an income tax allowance are recovered or refunded through a subsequent
true-up mechanism. As such, TrAIL recognizes revenue as it incurs recoverable costs and earns the allowed return.
Any differences between revenues earned based on actual costs and the amounts billed based on estimated costs
are recognized as a regulatory asset or liability and will be recovered or refunded, respectively, in subsequent
periods.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (net of any impairment recognized), including payroll and related
costs such as taxes, employee benefits, administrative and general costs, and Allowance for Funds Used During
Construction (AFUDC) on certain projects incurred to place the assets in service. The costs of normal maintenance,
repairs and minor replacements are expensed as incurred. TrAIL recognizes liabilities for planned major maintenance
projects as they are incurred.
TrAIL provides depreciation on a straight-line basis at various rates over the estimated lives of property included in
plan in service. The annual composite rate for TrAIL's transmission facilities was approximately 2.7% in 2011.
TrAIL has been granted certain incentives by FERC, including the inclusion of construction work in progress (CWIP)
in rate base for most components of the TrAIL Line. As a result, AFUDC is not applicable to such components of the
TrAIL Line.
TrAIL reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the
carrying amount of such an asset may not be recoverable. The recoverability of the long-lived asset is measured by
comparing the long-lived asset’s carrying value to the sum of undiscounted future cash flows expected to result from
the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows
of the long-lived asset, impairment exists and a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value.
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash
equivalents on the Balance Sheet at cost, which approximates their fair market value.
NEW ACCOUNTING PRONOUNCEMENTS
New accounting pronouncements, not yet effective, are not expected to have a material effect on TrAIL's financial
statements.
8
2. MERGER
On February 25, 2011, the merger between FirstEnergy and AE closed. Pursuant to the terms of the Agreement and
Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly owned subsidiary
of FirstEnergy (Merger Sub), and AE, Merger Sub merged with and into AE, with AE continuing as the surviving
corporation and becoming a wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders
received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the
date the merger was completed, and all outstanding AE equity-based employee compensation awards were
exchanged for FirstEnergy equity-based awards on the same basis. Total consideration in the merger was $4,354
million, based on the closing price of a share of FirstEnergy common stock on February 24, 2011, of which
approximately $426 million was attributable to TrAIL.
The following table summarizes the differences between the fair values and the carrying values of TrAIL’s assets and
liabilities that were “pushed down” as of the date of the merger:
(In millions)
$426
427
Purchase price attributable to TrAIL
Less: TrAIL net book value at merger date
$(1)
Purchase price below net book value
Fair value adjustments to assets acquired:
Increase in regulatory assets – recovery of long-term debt fair value adjustment
Fair value adjustments to liabilities assumed:
Increase in long-term debt
Unamortized long-term debt discounts
(10)
(1)
Net fair value adjustments
$(1)
$10
The estimated fair values of the assets acquired and liabilities assumed were determined based on the accounting
guidance under GAAP for fair value measurements. Fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement
date.
For purposes of measuring the fair value of regulated property, plant and equipment and regulatory assets acquired
and regulatory liabilities assumed, the fair values of these items approximates their book values due to historical costbased ratemaking. It is expected that current regulated operations will remain in a regulated environment for the
foreseeable future and this represents the highest and best use of those assets. Fair value adjustments relating to
TrAIL’s regulated debt have been reflected on the Balance Sheet with an offsetting regulatory asset based upon the
established regulatory authority regarding rate treatment for those specific liabilities.
3. TAXES
Income Taxes
TrAIL records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the
net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts recognized for tax purposes. Deferred income tax liabilities related to temporary tax and
accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in
effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates
expected to be in effect when they are settled. The following table presents the components of the provision for
income taxes:
9
Successor
Predecessor
February
25, 2011
January 1,
through 2011 through Year ended
December February 24, December
2011
31, 2011
31, 2010
(In millions)
Currently payable (receivable)Federal
State
Deferred, netFederal
State
$(16.3)
6.0
$7.5
1.9
$6.7
1.7
(10.3)
9.4
8.4
53.6
(0.5)
(1.3)
(0.2)
23.5
3.1
53.1
(1.5)
26.6
$42.8
$7.9
$35.0
TrAIL is party to an intercompany income tax allocation agreement with FirstEnergy and FirstEnergy’s other
subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy,
excluding any tax benefits derived from interest expense associated with acquisition indebtedness from FirstEnergy’s
merger with GPU are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is
accounted for as a capital contribution by the company receiving the tax benefit.
The following table provides a reconciliation of federal income tax expense at the federal statutory rate to the total
provision for income taxes for the periods February 25, 2011 through December 31, 2011, January 1, 2011 through
February 24, 2011 and the year ended December 31, 2010.
Successor
February 25,
2011 through
December 31,
2011
(In millions)
Book income before provision for income taxes
Predecessor
January 1, 2011
Year ended
through
December
February 24,
31, 2010
2011
$112.0
$18.7
$89.4
Federal income tax expense at statutory rate
Increases (reductions) resulting from:
AFUDC
State income tax, net of federal income tax benefit
Other, net
$39.2
$6.7
$31.2
(0.3)
3.6
0.3
1.0
0.2
(0.8)
4.5
0.1
$42.8
$7.9
$35.0
10
Accumulated deferred income taxes as of December 31, 2011 and 2010, were as follows:
Successor
2011
(In millions)
Accumulated deferred income tax assets:
Tax effect of net operating loss carryforwards
Other
Total accumulated deferred income tax assets
Predecessor
2010
$205.4
2.6
208.0
$ 1.6
1.6
269.4
39.8
3.9
21.2
24.8
10.4
Total accumulated deferred income tax liabilities
313.1
56.4
Total net deferred income tax liability
Deferred income taxes included in current assets (current liabilities)
105.1
65.7
54.8
(23.2)
$170.8
$31.6
Accumulated deferred income tax liabilities:
Property basis differences
Regulatory assets
Other
Total noncurrent net accumulated deferred income tax liability
In September 2010, President Obama signed into law the “Small Business Jobs Act”. That legislation includes an
extension of the bonus depreciation provision into 2011 for certain qualified property. This provision allowed TrAIL to
accelerate its depreciation deductions on qualifying property for federal income tax purposes.
TrAIL has recorded as deferred tax assets the effect of net operating losses that will more likely than not be realized
through future operations and through the reversal of existing temporary differences. In 2011, the tax benefit of
operating loss carryforwards included in deferred tax expense was $205 million. Of this amount, $65.7 million is
expected to be utilized in 2012. As of December 31, 2011, the deferred income tax assets consisted of $174 million of
federal net operating loss carryforwards that expire in 2031 and $31 million of state net operating loss carryforwards
that expire in 2031.
General Taxes
General taxes consisted of the following:
Successor
February 25,
2011 through
December 31, 2011
(In millions)
Real and personal property
Social security and unemployment
Other
Total general taxes
11
Predecessor
January 1,
Year ended
2011 through
December
February 24, 2011
31, 2010
$1.5
0.5
0.4
$0.2
0.1
-
$1.4
0.5
0.2
$2.4
$0.3
$2.0
4. INTANGIBLE ASSETS
Intangible assets included in “Property, plant and equipment, net” on the Balance Sheets as of December 31, 2011
and 2010, were as follows:
Predecessor
December 31, 2010
Successor
December 31, 2011
Gross
Carrying
Amount
(In millions)
Accumulated
Amortization
Gross
Carrying
Amount
Accumulated
Amortization
Software
Land easements
$19.0
38.4
$1.3
0.4
$5.8
2.9
$-
Total
$57.4
$1.7
$8.7
$-
Future amortization expense for intangible assets as of December 31, 2011, is estimated to be $2.4 million annually
from 2012 through 2016.
5. FAIR VALUE MEASUREMENTS
The following table provides the approximate fair value and related carrying amounts of long-term debt as of
December 31, 2011, and December 31, 2010:
Successor
2011
Carrying
Amount
(In millions)
$458.0
Long-term debt
Fair
Value
$478.4
Predecessor
2010
Carrying
Amount
$818.6
Fair
Value
$828.6
The fair values of long-term debt reflect the present value of the cash outflows relating to those obligations based on
the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective
period. The yields assumed were based on debt with similar characteristics offered by corporations with credit ratings
similar to those of TrAIL.
6. DEBT AND CREDIT FACILITIES
DEBT
TrAIL’s long-term debt consisted of the following:
(Dollar amounts in millions)
Medium-Term Notes
Revolving Loan (variable rate)
Successor
As of December 31, 2011
December 31,
Maturity Date Interest Rate %
2011
2015
4.000
$458.0
2013
3.287
-
Predecessor
December 31,
2010
$450.0
370.0
458.0
820.0
-
(1.4)
$458.0
$818.6
Total long-term debt
Net unamortized debt discount
Total long-term debt and other long-term
obligations
12
CREDIT FACILITY
TrAIL had in place the following revolving credit facility as of December 31, 2011:
(Dollar amounts in millions)
Matures
Revolving credit facility ...............................
2013
Total
Capacity
Borrowed
$450.0
Letters of
Credit Issued
$-
$-
Available
Capacity
$450.0
7. REGULATORY MATTERS
State Regulation Matters
Pennsylvania
By order entered on December 12, 2008, the Pennsylvania Public Utility Commission (PPUC) authorized TrAIL to
construct a 1.2 mile portion of TrAIL in Pennsylvania from the proposed 502 Junction Substation in Greene County to
the Pennsylvania-West Virginia state line. In the same order, the PPUC also authorized TrAIL to engage in a
collaborative process to identify possible solutions to reliability problems in the Washington County, Pennsylvania
area in lieu of the Prexy Facilities that had been a part of the original TrAIL proposal. As a result of the collaborative
process, a settlement and an amendment to the application based on a consensus of the participants in the
collaborative process was approved by the PPUC on November 19, 2010.
8. COMMITMENTS AND CONTINGENCIES
There are various lawsuits, claims and proceedings related to TrAIL’s normal business operations pending against
TrAIL. TrAIL accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs
and can reasonably estimate the amount of such costs. In cases where TrAIL determines that it is not probable, but
reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of
loss if such estimate can be made. If it were ultimately determined that TrAIL has legal liability or is otherwise made
subject to liability it could have a material adverse effect on TrAIL's financial condition, results of operations and cash
flows.
9. TRANSACTIONS WITH AFFILIATED COMPANIES
The affiliated company transactions for TrAIL are as follows:
Successor
February 25,
2011 through
December 31,
2011
(In millions)
Predecessor
January 1,
2011
through
February 24,
2011
2010
Total billings by AESC for pension and OPEB costs
$1.8
$-
$2.4
Total billings by FESC for other operating costs
$2.4
$-
$-
13

FirstEnergy Transmission Affiliates Pre-Qualification

Transcription

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